Exco Resources (EXCO) 10-Q 2013 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________

FORM 10-Q

______________________________

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2013

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from             to            

Commission File Number 001-32743

______________________________ 

EXCO RESOURCES, INC.

(Exact name of registrant as specified in its charter)

______________________________

Texas	74-1492779
(State of incorporation)	(I.R.S. Employer Identification No.)
12377 Merit Drive Suite 1700, LB 82 Dallas, Texas	75251
(Address of principal executive offices)	(Zip Code)

(214) 368-2084

(Registrant’s telephone number, including area code)

______________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    YES  x    NO  o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant is required to submit and post such files).    YES  x    NO  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	x	Accelerated filer	o
Non-accelerated filer	o  (Do not check if a smaller reporting company)	Smaller reporting company	o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    YES  o    NO  x

The number of shares of common stock, par value $0.001 per share, outstanding as of April 25, 2013 was 217,537,246.

EXCO RESOURCES, INC.

INDEX

PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Condensed Consolidated Balance Sheets at March 31, 2013 and December 31, 2012	2
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2013 and 2012	4
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012	5
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Three Months Ended March 31, 2013 and 2012	6
	Notes to Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	46
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 6.	Exhibits	47
	Signatures	48

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)	March 31, 2013			December 31, 2012
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	26,646		$	45,644
Restricted cash	53,292			70,085
Accounts receivable, net:
Oil and natural gas	70,687			84,348
Joint interest	71,690			69,446
Other	18,230			15,053
Inventory	4,218			5,705
Derivative financial instruments	10,653			49,500
Other	18,647			22,085
Total current assets	274,063			361,866
Equity investments	359,739			347,008
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	389,998			470,043
Proved developed and undeveloped oil and natural gas properties	2,618,292			2,715,767
Accumulated depletion	(1,984,556		)	(1,945,565		)
Oil and natural gas properties, net	1,023,734			1,240,245
Gas gathering assets	33,810			130,830
Accumulated depreciation and amortization	(9,236		)	(34,364		)
Gas gathering assets, net	24,574			96,466
Office, field and other equipment, net	19,156			20,725
Deferred financing costs, net	19,257			22,584
Derivative financial instruments	6,440			16,554
Goodwill	163,155			218,256
Other assets	28			28
Total assets	$	1,890,146		$	2,323,732
See accompanying notes.

2

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except per share and share data)	March 31, 2013			December 31, 2012
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	59,125		$	83,240
Revenues and royalties payable	112,710			134,066
Accrued interest payable	3,089			17,029
Current portion of asset retirement obligations	395			1,200
Income taxes payable	—			—
Derivative financial instruments	17,639			2,396
Total current liabilities	192,958			237,931
Long-term debt	1,331,376			1,848,972
Deferred income taxes	—			—
Derivative financial instruments	23,783			26,369
Asset retirement obligations and other long-term liabilities	42,085			61,067
Commitments and contingencies	—			—
Shareholders’ equity:
Preferred stock, $0.001 par value; 10,000,000 authorized shares; none issued and outstanding	—			—
Common stock, $0.001 par value; 350,000,000 authorized shares; 218,049,105 shares issued and 217,509,884 shares outstanding at March 31, 2013; 218,126,071 shares issued and 217,586,850 shares outstanding at December 31, 2012	215			215
Additional paid-in capital	3,203,364			3,200,067
Accumulated deficit	(2,896,156		)	(3,043,410		)
Treasury stock, at cost; 539,221 shares at March 31, 2013 and December 31, 2012	(7,479		)	(7,479		)
Total shareholders’ equity	299,944			149,393
Total liabilities and shareholders’ equity	$	1,890,146		$	2,323,732

See accompanying notes.

3

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended March 31,
(in thousands, except per share data)	2013			2012
Revenues:
Oil and natural gas	$	138,223		$	134,848
Costs and expenses:
Oil and natural gas operating costs	13,617			22,796
Production and ad valorem taxes	5,248			7,193
Gathering and transportation	24,476			26,423
Depletion, depreciation and amortization	41,308			89,582
Write-down of oil and natural gas properties	10,707			275,864
Accretion of discount on asset retirement obligations	690			947
General and administrative	17,984			21,505
(Gain) loss on divestitures and other operating items	(184,882		)	1,625
Total costs and expenses	(70,852		)	445,935
Operating income (loss)	209,075			(311,087		)
Other income (expense):
Interest expense	(20,192		)	(16,764		)
Gain (loss) on derivative financial instruments	(43,514		)	53,865
Other income	88			243
Equity income (loss)	12,663			(7,906		)
Total other income (expense)	(50,955		)	29,438
Income (loss) before income taxes	158,120			(281,649		)
Income tax expense	—			—
Net income (loss)	$	158,120		$	(281,649	)
Earnings (loss) per common share:
Basic:
Net income (loss)	$	0.74		$	(1.32	)
Weighted average common shares outstanding	214,784			214,145
Diluted:
Net income (loss)	$	0.74		$	(1.32	)
Weighted average common and common equivalent shares outstanding	214,861			214,145

See accompanying notes.

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
(in thousands)	2013			2012
Operating Activities:
Net income (loss)	$	158,120		$	(281,649	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	41,308			89,582
Share-based compensation expense	1,735			2,864
Accretion of discount on asset retirement obligations	690			947
Write-down of oil and natural gas properties	10,707			275,864
(Income) loss from equity investments	(12,663		)	7,906
Non-cash change in fair value of derivatives	60,232			(3,720		)
Deferred income taxes	—			—
Amortization of deferred financing costs and discount on the 2018 Notes	5,113			1,750
Gain on divestitures	(187,038		)	—
Effect of changes in:
Accounts receivable	8,518			78,796
Other current assets	(1,628		)	1,871
Accounts payable and other current liabilities	(41,880		)	(29,088		)
Net cash provided by operating activities	43,214			145,123
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(72,911		)	(169,756		)
Property acquisitions	(33,390		)	(1,402		)
Equity method investments	(68		)	(137		)
Proceeds from disposition of property and equipment	611,203			981
Restricted cash	16,793			(8,117		)
Net changes in advances from Appalachia JV	3,633			10,543
Net cash provided by (used in) investing activities	525,260			(167,888		)
Financing Activities:
Borrowings under credit agreements	46,757			53,000
Repayments under credit agreements	(623,266		)	(23,000		)
Proceeds from issuance of common stock	22			2
Payment of common stock dividends	(10,739		)	(8,663		)
Deferred financing costs and other	(246		)	—
Net cash provided by (used in) financing activities	(587,472		)	21,339
Net decrease in cash	(18,998		)	(1,426		)
Cash at beginning of period	45,644			31,997
Cash at end of period	$	26,646		$	30,571
Supplemental Cash Flow Information:
Cash interest payments	$	33,624		$	34,883
Income tax payments	$	—		$	—
Supplemental non-cash investing and financing activities:
Capitalized share-based compensation	$	1,527		$	1,931
Capitalized interest	$	5,079		$	6,302
Issuance of common stock for director services	$	13		$	17
Accrued restricted stock dividends	$	127		$	97
Debt assumed upon formation of EXCO/HGI Partnership, net	$	58,613		$	—

See accompanying notes.

5

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

	Common Stock				Treasury Stock					Additional paid-in capital		Accumulated deficit			Total shareholders’ equity
(in thousands)	Shares		Amount		Shares		Amount
Balance at December 31, 2011	217,245		$	215	(539	)	$	(7,479	)	$	3,181,063	$	(1,615,467	)	$	1,558,332
Issuance of common stock	2		—		—		—			19		—			19
Share-based compensation	—		—		—		—			4,795		—			4,795
Restricted stock issued, net of cancellations	(49	)	—		—		—			—		—			—
Common stock dividends	—		—		—		—			—		(8,663		)	(8,663		)
Net loss	—		—		—		—			—		(281,649		)	(281,649		)
Balance at March 31, 2012	217,198		$	215	(539	)	$	(7,479	)	$	3,185,877	$	(1,905,779	)	$	1,272,834
Balance at December 31, 2012	218,126		$	215	(539	)	$	(7,479	)	$	3,200,067	$	(3,043,410	)	$	149,393
Issuance of common stock	3		—		—		—			35		—			35
Share-based compensation	—		—		—		—			3,262		—			3,262
Restricted stock issued, net of cancellations	(80	)	—		—		—			—		—			—
Common stock dividends	—		—		—		—			—		(10,866		)	(10,866		)
Net income	—		—		—		—			—		158,120			158,120
Balance at March 31, 2013	218,049		$	215	(539	)	$	(7,479	)	$	3,203,364	$	(2,896,156	)	$	299,944

See accompanying notes.

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EXCO RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Organization and basis of presentation

Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “EXCO,” “EXCO Resources,” “Company,” “we,” “us,” and “our” are to EXCO Resources, Inc. and its consolidated subsidiaries.

We are an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and production of onshore U.S. oil and natural gas properties. Our principal operations are conducted in certain key U.S. oil and natural gas areas including East Texas, North Louisiana, Appalachia and the Permian Basin in West Texas. In addition to our oil and natural gas producing operations, we own 50% interests in two midstream joint ventures located in East Texas/North Louisiana and Appalachia. Our midstream joint ventures are treated as a separate business segment.

Our operations are principally conducted through several joint venture arrangements. We manage our business development and other exploration and production activities through our parent entity. A brief description of each joint venture follows:

•East Texas/North Louisiana JV

A joint venture with BG Group, plc, or BG Group, covering an undivided 50% interest in our Haynesville/Bossier shale assets in East Texas and North Louisiana, or the East Texas/North Louisiana JV. The East Texas/North Louisiana JV is governed by a joint development agreement with our subsidiary, EXCO Operating Company, LP, or EXCO Operating, serving as operator. We report the operating results and financial position of the East Texas/North Louisiana JV using proportional consolidation. The East Texas/North Louisiana JV previously held certain conventional shallow producing assets that were contributed to the EXCO/HGI Partnership, as defined below, upon its formation on February 14, 2013. In addition, BG Group sold all of its conventional shallow assets within the East Texas/North Louisiana JV to the EXCO/HGI Partnership in March 2013.

•TGGT

A joint venture with BG Group in which we each own a 50% interest in TGGT Holdings, LLC, or TGGT, which holds most of our East Texas/North Louisiana midstream assets. We use the equity method to account for our 50% investment in TGGT.

•Appalachia JV

A joint venture with BG Group covering our shallow producing assets and Marcellus shale properties in the Appalachia region, or the Appalachia JV. EXCO and BG Group each own an undivided 50% interest in the Appalachia JV and a 49.75% working interest in the joint venture's properties. The remaining 0.5% working interest is owned by a jointly owned operating entity, or OPCO, that manages the Appalachia JV operations. We use the equity method to account for our investment in OPCO and proportionally consolidate our 49.75% interest in the Appalachia JV.

•Appalachia Midstream JV

A joint venture with BG Group in which we each own a 50% interest in a midstream company, or the Appalachia Midstream JV, which plans to develop infrastructure and provide take-away capacity in the Marcellus shale. We use the equity method to account for our 50% investment in the Appalachia Midstream JV.

•EXCO/HGI Partnership

A joint venture formed on February 14, 2013, with the Harbinger Group Inc., or HGI, in which we own a 25.5% economic interest in conventional non-shale assets in East Texas and North Louisiana and shallow Canyon Sand and other assets in the Permian Basin of West Texas, or the EXCO/HGI Partnership. We report our 25.5% interest in the EXCO/HGI Partnership using proportional consolidation. From January 1, 2013 to February 13, 2013, our operating results reflect 100% of our interest in the properties we contributed to the EXCO/HGI Partnership. From February 14, 2013 to March 31, 2013, our operating results reflect 25.5% of our interest in the properties we contributed to the EXCO/HGI Partnership.

The accompanying Condensed Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012, Condensed Consolidated Statements of Operations, Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the three months ended March 31, 2013 and 2012 are for EXCO and its consolidated subsidiaries. The condensed consolidated financial statements and related footnotes are presented in accordance with generally accepted accounting principles in the United States, or GAAP.

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We have prepared the accompanying unaudited interim financial statements pursuant to the rules and regulations of the Securities and Exchange Commission, or the SEC, and in the opinion of management, such financial statements reflect all adjustments necessary to present fairly the consolidated financial position of EXCO at March 31, 2013 and its results of operations and cash flows for the periods presented. We have omitted certain information and disclosures normally included in annual financial statements prepared in accordance with GAAP pursuant to those rules and regulations, although we believe that the disclosures we have made are adequate to make the information presented not misleading. These unaudited interim financial statements should be read in conjunction with our audited consolidated financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC on February 21, 2013.

In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures. The results of operations for the interim periods are not necessarily indicative of the results we expect for the full year.

2. Significant accounting policies

We consider accounting policies related to our estimates of proved reserves, accounting for derivatives, business combinations, share-based payments, oil and natural gas properties, goodwill, revenue recognition, asset retirement obligations and income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies and others are summarized in our Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC on February 21, 2013.

Recent accounting pronouncement

In February 2013, the Financial Accounting Standards Board, or the FASB, issued Accounting Standards Update, or ASU, No. 2013-04, Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date, or ASU 2013-04. ASU 2013-04 provides guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations addressed within existing guidance in GAAP. The update is effective for interim and annual periods beginning after December 15, 2013 and is required to be applied retrospectively to all prior periods presented for those obligations that existed upon adoption of ASU 2013-04. We are presently assessing the potential impact of ASU 2013-04.

3. Divestitures, acquisitions and other significant events

EXCO/HGI Partnership

On February 14, 2013, we formed a partnership with HGI. Pursuant to the agreements governing the transaction, we contributed our conventional non-shale assets in East Texas and North Louisiana and our shallow Canyon Sand and other assets in the Permian Basin of West Texas to the EXCO/HGI Partnership, in exchange for net proceeds of $573.3 million, after customary preliminary purchase price adjustments, and a 25.5% economic interest in the partnership. HGI's economic interest in the EXCO/HGI Partnership is 74.5%. The primary strategy of the EXCO/HGI Partnership is to acquire conventional producing oil and natural gas properties to enhance asset value and cash flow.

The contribution of oil and natural gas properties to the EXCO/HGI Partnership resulted in a significant alteration in our depletion rate. In accordance with full cost accounting rules, we recorded a gain of $187.0 million, net of a proportionate reduction in goodwill of $55.1 million, during the three months ended March 31, 2013.

Immediately following the closing, the EXCO/HGI Partnership entered into an agreement to purchase the remaining shallow Cotton Valley assets within the East Texas/North Louisiana JV from an affiliate of BG Group, for $130.9 million, after customary preliminary purchase price adjustments. The assets acquired as a result of this transaction represented an incremental working interest in properties owned by the EXCO/HGI Partnership. The transaction closed on March 5, 2013 and was funded with borrowings from the EXCO/HGI Partnership's credit agreement, or the EXCO/HGI Partnership Credit Agreement.

Acreage transaction

On March 13, 2013, we closed a sale and joint development agreement with a private party for the sale of an undivided 50% of our interest in certain undeveloped acreage. We received $37.9 million in cash, after final closing adjustments. In addition to the cash consideration received at closing, the purchaser agreed to fund our share of drilling and completion costs within the joint venture area up to $18.9 million, with any remaining unfunded amount paid to us by June 30, 2016.

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4. Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the three months ended March 31, 2013:

(in thousands)
Asset retirement obligations at January 1, 2013	$	61,864
Activity during the period:
Liabilities incurred during the period	21
Liabilities settled during the period	(54		)
Adjustment to liability due to acquisitions	1,895
Adjustment to liability due to divestitures	(28,315		)
Accretion of discount	690
Asset retirement obligations at March 31, 2013	36,101
Less current portion	395
Long-term portion	$	35,706

Our asset retirement obligations are determined using discounted cash flow methodologies based on inputs that are not readily available in public markets. We have no assets that are legally restricted for purposes of settling asset retirement obligations.

5. Oil and natural gas properties

The accounting for, and disclosure of, oil and natural gas producing activities require that we choose between two GAAP alternatives; the full cost method or the successful efforts method. We use the full cost method of accounting, which involves capitalizing all intangible drilling costs, lease and well equipment and exploration and development costs incurred plus acquired proved and unproved leaseholds. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. Our unproved property costs, which include unproved oil and natural gas properties, properties under development, and major development projects, collectively totaled $390.0 million and $470.0 million as of March 31, 2013 and December 31, 2012, respectively, and are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extensions or discoveries from drilling operations or determination that no proved reserves are attributable to such costs. We expect these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. There were no impairments of unproved properties during the three months ended March 31, 2013 and 2012.

When we acquire significant amounts of undeveloped acreage, we capitalize interest on the acquisition costs in accordance with FASB Accounting Standards Codification, or ASC, Subtopic835-20, Capitalization of Interest. When the unproved property costs are moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we cease capitalizing interest.

We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unproved properties, and all estimated future development costs less estimated salvage value are divided by the total estimated quantities of proved reserves. This rate is applied to our total production for the quarter, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our exploration, exploitation and development activities.

Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss, unless the disposition would significantly alter the depletion rate and/or the relationship between capitalized costs and proved reserves.

Pursuant to Rule 4-10(c)(4) of Regulation S-X, at the end of each quarterly period, companies that use the full cost method of accounting for their oil and natural gas properties must compute a limitation on capitalized costs, or ceiling test. The ceiling test involves comparing the net book value of the full cost pool, after taxes, to the full cost ceiling limitation defined below. In the event the full cost ceiling is less than the full cost pool, we are required to record a ceiling test write-down of our oil and natural gas properties. The full cost ceiling limitation is computed as the sum of the present value of estimated future net revenues from our proved reserves by applying average price as prescribed by SEC Release No. 33-8995, less estimated future expenditures (based on current costs) to develop and produce the proved reserves, discounted at 10%, plus the cost of

9

properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects.

The ceiling test is computed using the simple average spot price for the trailing twelve month period using the first day of each month. For the period ended March 31, 2013, the trailing twelve month reference price was $2.95 per Mmbtu for natural gas at Henry Hub, $92.63 per Bbl for the West Texas Intermediate oil at Cushing, Oklahoma, and $44.36 per Bbl for natural gas liquids based on the twelve month average of realized prices. Each of the reference prices for oil and natural gas are further adjusted for quality factors and regional differentials to derive estimated future net revenues. Under full cost accounting rules, any ceiling test write-downs of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedges, we are not allowed to use the impacts of the derivative financial instruments in our ceiling test computations. For the three months endedMarch 31, 2013 and 2012, we recognized pre-tax ceiling test write-downs of $10.7 million and $275.9 million to our proved oil and natural gas properties, respectively.

The ceiling test calculation is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil, natural gas and natural gas liquids that are ultimately recovered.

6. Earnings per share

The following table presents the basic and diluted earnings per share computations:

	Three Months Ended March 31,
(in thousands, except per share data)	2013		2012
Basic net income (loss) per common share:
Net income (loss)	$	158,120	$	(281,649	)
Weighted average common shares outstanding	214,784		214,145
Net income (loss) per basic common share	$	0.74	$	(1.32	)
Diluted net income (loss) per common share:
Net income (loss)	$	158,120	$	(281,649	)
Weighted average common shares outstanding	214,784		214,145
Dilutive effect of:
Stock options	5		—
Restricted shares	72		—
Weighted average common and common share equivalents outstanding	214,861		214,145
Net income (loss) per diluted common share	$	0.74	$	(1.32	)

Diluted earnings per common share are computed in the same manner as basic earnings per share after assuming the issuance of common stock for all potentially dilutive common share equivalents, which include both stock options and restricted stock awards, whether vested or not. The computation of diluted earnings per share excluded 16,582,021 and 18,132,804 antidilutive common share equivalents for the three months ended March 31, 2013 and 2012, respectively. The antidilutive common share equivalents primarily related to out-of-the-money stock options for the three months ended March 31, 2013.

7. Derivative financial instruments

Our primary objective in entering into derivative financial instruments is to manage our exposure to commodity price fluctuations, protect our returns on investments and achieve a more predictable cash flow from our operations. These transactions limit exposure to declines in commodity prices, but also limit the benefits we would realize if commodity prices increase. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expense due to changes in the fair value of our derivative financial instrument contracts. Cash charges or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration. We do not designate our derivative financial instruments as

10

hedging instruments for financial accounting purposes and, as a result, we recognize the change in the respective instruments’ fair value in earnings.

The table below outlines the classification of our derivative financial instruments on our Condensed Consolidated Balance Sheets and their financial impact in our Condensed Consolidated Statements of Operations.

Fair Value of Derivative Financial Instruments

(in thousands)		March 31, 2013			December 31, 2012
Commodity contracts	Derivative financial instruments - Current assets	$	10,653		$	49,500
Commodity contracts	Derivative financial instruments - Long-term assets	6,440			16,554
Commodity contracts	Derivative financial instruments - Current liabilities	(17,639		)	(2,396		)
Commodity contracts	Derivative financial instruments - Long-term liabilities	(23,783		)	(26,369		)
Net derivative financial instruments		$	(24,329	)	$	37,289

Effect of Derivative Financial Instruments

	Three Months Ended March 31,
(in thousands)	2013			2012
Cash settlements on derivative financial instruments	$	16,718		$	50,145
Non-cash change in fair value of derivative financial instruments	(60,232		)	3,720
Gain (loss) on derivative financial instruments	$	(43,514	)	$	53,865

Settlements in the normal course of maturities of our derivative financial instrument contracts result in cash receipts from, or cash disbursements to, our derivative contract counterparties. Changes in the fair value of our derivative financial instrument contracts, which includes both cash settlements and non-cash changes in fair value, are included in earnings with a corresponding increase or decrease in the Condensed Consolidated Balance Sheets fair value amounts.

Our natural gas and oil derivative instruments are comprised of swap and call option contracts. Swap contracts allow us to receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. Call options are financial contracts that give our trading counterparties the right, but not the obligation to buy an agreed quantity of natural gas from us at a certain time and price in the future. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess. If the market price settles below the fixed price of the call option, no payment is due from either party. In exchange for selling this option, we received upfront proceeds which we used to obtain a higher fixed price on our swaps.   

We place our derivative financial instruments with the financial institutions that are lenders under our respective credit agreements that we believe have high quality credit ratings. To mitigate our risk of loss due to default, we have entered into master netting agreements with our counterparties on our derivative financial instruments that allow us to offset our asset position with our liability position in the event of a default by the counterparty. We proportionately consolidate the derivative financial instruments entered into by the EXCO/HGI Partnership, however the contracts of the EXCO/HGI Partnership involve separate master netting agreements with their counterparties and we are not liable in the event of default.

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The following table presents the volumes and fair value of our oil and natural gas derivative financial instruments (including our 25.5% proportionate interest in the EXCO/HGI Partnership's derivative financial instruments) as of March 31, 2013:

(in thousands, except prices)	Volume Mmbtus/Bbls	Weighted average strike price per Mmbtu/Bbl		Fair value at March 31, 2013
Natural gas:
Swaps:
Remainder of 2013	66,835	$	4.13	$	639
2014	56,648	4.25		1,009
2015	28,288	4.31		309
Calls:
Remainder of 2013	15,125	4.29		(2,855		)
2014	20,075	4.29		(8,362		)
2015	20,075	4.29		(11,267		)
Total natural gas	207,046			$	(20,527	)
Oil:
Swaps:
Remainder of 2013	105	$	94.05	$	(278	)
2014	93	91.87		(78		)
2015	—	—		—
Calls:
Remainder of 2013	—	—		—
2014	365	100.00		(1,615		)
2015	365	100.00		(1,831		)
Total oil	928			$	(3,802	)
Total oil and natural gas derivatives				$	(24,329	)

At December 31, 2012, we had outstanding derivative contracts to mitigate price volatility covering 216,263 Mmmbtus of natural gas and 1,095 Mbbls of oil. At March 31, 2013, the average forward NYMEX oil prices per Bbl for the remainder of 2013 and calendar years 2014 and 2015 were $96.78, $92.75, and $89.33, respectively, and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2013 and calendar years 2014 and 2015 were $4.12, $4.23 and $4.30, respectively.

Our derivative financial instruments covered approximately 45.5% and 42.4% of production volumes for the three months ended March 31, 2013 and 2012, respectively.

8. Fair value measurements

We value our derivatives according to FASB ASC Topic 820, Fair Value Measurements and Disclosures, which defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. This fair value may be different from the settlement value based on company-specific inputs, such as credit rating, futures markets and forward curves, and readily available buyers or sellers for such assets or liabilities.

We categorize the inputs used in measuring fair value into a three-tier fair value hierarchy. These tiers include:

Level 1 – Observable inputs, such as quoted market prices in active markets, for substantially identical assets and liabilities.

Level 2 – Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. These include quoted prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data. If the asset or liability has a specified or contractual term, the input must be observable for substantially the full term of the asset or liability.

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Level 3 – Unobservable inputs that are supported by little or no market activity, generally requiring development of fair value assumptions by management.

Fair value of derivative financial instruments

The following table presents a summary of the estimated fair value of our derivative financial instruments as of March 31, 2013 and December 31, 2012. During the three months ended March 31, 2013, there were no changes in the fair value level classifications.

	March 31, 2013
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	(24,329	)	$	—	$	(24,329	)
	December 31, 2012
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	37,289		$	—	$	37,289

We evaluate derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties, but report them on a gross basis on the Condensed Consolidated Balance Sheets. Net derivative asset values are determined primarily by quoted futures prices and utilization of the counterparties’ credit-adjusted risk-free rate curves and net derivative liabilities are determined by utilization of our credit-adjusted risk-free rate curve or the credit-adjusted risk-free rate curve of the EXCO/HGI Partnership. The credit-adjusted risk-free rates of our counterparties are based on an independent market-quoted credit default swap rate curve for the counterparties’ debt plus the London Interbank Offered Rate, or LIBOR, curve as of the end of the reporting period. Our credit-adjusted risk-free rate is based on the blended rate of independent market-quoted credit default swap rate curves for companies that have the same credit rating as us plus the LIBOR curve as of the end of the reporting period. In addition, the credit-adjusted risk-free rate for the EXCO/HGI Partnership is based on the cost of debt plus the LIBOR curve as of the end of the reporting period.

The valuation of our commodity price derivatives, represented by oil and natural gas swaps and call option contracts, is discussed below.

Oil derivatives. Our oil derivatives are swap and call option contracts for notional Bbls of oil at fixed (in the case of swap contracts) or interval (in the case of call option contracts) NYMEX West Texas Intermediate, or WTI, oil prices. The asset and liability values attributable to our oil derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil, (iii) the applicable estimated credit-adjusted risk-free rate curve, as described above, and (iv) the implied rate of volatility inherent in the call option contracts. The implied rates of volatility were determined based on average WTI oil prices.

Natural gas derivatives. Our natural gas derivatives are swap and call option contracts for notional Mmbtus of gas at posted price indexes, including NYMEX Henry Hub, or HH, swap and call option contracts. The asset and liability values attributable to our natural gas derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH for natural gas swaps, (iii) the applicable credit-adjusted risk-free rate curve, as described above and (iv) the implied rate of volatility inherent in the call option contracts. The implied rates of volatility were determined based on average HH natural gas prices.

See further details on the fair value of our derivative financial instruments in “Note 7. Derivative financial instruments.”

Fair value of other financial instruments

Our financial instruments include cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities. The carrying amount of these instruments approximates fair value because of their short-term nature.

The carrying values of the EXCO Resources Credit Agreement and EXCO/HGI Partnership Credit Agreement approximate fair value, as these are subject to short-term floating interest rates that approximate the rates available to us for those periods.

The estimated fair value of our 7.5% senior unsecured notes due September 15, 2018, or the 2018 Notes, at March 31, 2013 and December 31, 2012 is presented below. The estimated fair value of the 2018 Notes has been calculated based on market quotes.

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	March 31, 2013
(in thousands)	Level 1		Level 2		Level 3		Total
2018 Notes	$	712,973	$	—	$	—	$	712,973
	December 31, 2012
(in thousands)	Level 1		Level 2		Level 3		Total
2018 Notes	$	716,250	$	—	$	—	$	716,250

9. Long-term debt

Our total debt is summarized as follows:

(in thousands)	March 31, 2013			December 31, 2012
EXCO Resources Credit Agreement	$	494,234		$	1,107,500
2018 Notes	750,000			750,000
Unamortized discount on 2018 Notes	(8,228		)	(8,528		)
Total debt excluding the EXCO/HGI Partnership	$	1,236,006		$	1,848,972
EXCO/HGI Partnership Credit Agreement	95,370			—
Total debt	$	1,331,376		$	1,848,972

Terms and conditions of each of these debt obligations are discussed below.

EXCO Resources Credit Agreement

As of March 31, 2013, the EXCO Resources Credit Agreement had a borrowing base of $900.0 million, with $494.2 million of outstanding indebtedness and $398.3 million of available borrowing capacity. On March 31, 2013, the one month LIBOR was 0.2%, which would result in an interest rate of approximately 2.5%. The borrowing base is redetermined semi-annually, with us and the lenders having the right to request interim unscheduled redeterminations in certain circumstances. Upon formation of the EXCO/HGI Partnership, as discussed in "Note 3. Divestitures, acquisitions and other significant events," we used the proceeds of $573.3 million to pay down the EXCO Resources Credit Agreement and the borrowing base was reduced to $900.0 million. The maturity date of the EXCO Resources Credit Agreement is April 1, 2016.

The majority of our subsidiaries are guarantors under the EXCO Resources Credit Agreement. The EXCO Resources Credit Agreement permits investments, loans and advances to the unrestricted subsidiaries related to our joint ventures with certain limitations, and allows us to repurchase up to $200.0 million of our common stock, of which $7.5 million has been spent to repurchase shares as of March 31, 2013.

Borrowings under the EXCO Resources Credit Agreement are collateralized by first lien mortgages providing a security interest of not less than 80% of the engineered value, as defined in the agreement, in our oil and natural gas properties covered by the borrowing base. We are permitted to have derivative financial instruments covering no more than 100% of forecasted production from total proved reserves, as defined in the agreement, during the first two years of the forthcoming five-year period, 90% of the forecasted production for any month during the third year of the forthcoming five-year period and 85% of the forecasted production from total proved reserves during the fourth and fifth years of the forthcoming five-year period.

The EXCO Resources Credit Agreement sets forth the terms and conditions under which we are permitted to pay a cash dividend on our common stock and provides that we may declare and pay cash dividends on our common stock in an amount not to exceed $50.0 million in any four consecutive fiscal quarters, provided that, as of each payment date and after giving effect to the dividend payment date, (i) no default has occurred and is continuing, (ii) we have at least 10% of our borrowing base available under the EXCO Resources Credit Agreement, and (iii) payment of such dividend is permitted under the indenture governing the 2018 Notes.

As of March 31, 2013, we were in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, which require that we:

• maintain a consolidated current ratio (as defined in the EXCO Resources Credit Agreement) of at least 1.0 to 1.0 as of the end of any fiscal quarter; and

• not permit our ratio of consolidated funded indebtedness to consolidated EBITDAX (as defined in the EXCO Resources Credit Agreement) to be greater than 4.5 to 1.0 at the end of any fiscal quarter.

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While we believe our existing capital resources, including our cash flow from operations and borrowing capacity under the EXCO Resources Credit Agreement is sufficient to conduct our operations through 2013 and into 2014, there are certain risks arising from depressed natural gas prices and declines in production volumes that could impact our ability to meet debt covenants in future periods. In particular, our consolidated funded indebtedness to consolidated EBITDAX, as defined in the EXCO Resources Credit Agreement, is computed using the trailing twelve month EBITDAX and only includes operations from non-guarantor subsidiaries and unconsolidated joint ventures to the extent that cash is distributed to entities under the EXCO Resources Credit Agreement. As a result, our ability to maintain compliance with this covenant may be negatively impacted when oil and/or natural gas prices remain depressed for an extended period of time.

In response to the depressed natural gas prices, we have reduced our drilling plans which will result in lower expected production volumes during 2013 and into 2014, and we have reduced operating and administrative expenses. The combination of our reduced borrowing base, lower production volumes and the expiration of higher priced derivative financial instruments may require us to seek alternative financing arrangements, further reduce costs including drilling activity, or sell assets.

2018 Notes

The 2018 Notes are guaranteed on a senior unsecured basis by a majority of EXCO’s subsidiaries, with the exception of certain non-guarantor subsidiaries, our jointly-held equity investments with BG Group and the EXCO/HGI Partnership. Our equity investments with BG Group, other than OPCO, have been designated as unrestricted subsidiaries under the indenture governing the 2018 Notes.

As of March 31, 2013, $750.0 million in principal was outstanding on the 2018 Notes. The unamortized discount on the 2018 Notes at March 31, 2013 was $8.2 million. Interest accrues at 7.5% and is payable semi-annually in arrears on March 15th and September 15th of each year.

The indenture governing the 2018 Notes contains covenants, which may limit our ability and the ability of our restricted subsidiaries to:

• incur or guarantee additional debt and issue certain types of preferred stock;

• pay dividends on our capital stock (over $50.0 million per annum) or redeem, repurchase or retire our capital stock or subordinated debt;

• make certain investments;

• create liens on our assets;

• enter into sale/leaseback transactions;

• create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us;

• engage in transactions with our affiliates;

• transfer or issue shares of stock of subsidiaries;

• transfer or sell assets; and

• consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries.

EXCO/HGI Partnership Credit Agreement

In connection with its formation, the EXCO/HGI Partnership entered into a credit agreement, or the EXCO/HGI Partnership Credit Agreement, with an initial borrowing base of $400.0 million, of which $230.0 million was drawn at closing. Borrowings under the EXCO/HGI Partnership Credit Agreement are secured by properties owned by the EXCO/HGI Partnership and we do not guarantee the EXCO/HGI Partnership's debt. The EXCO/HGI Partnership is not a guarantor to the EXCO Resources Credit Agreement or the 2018 Notes.

As of March 31, 2013, $374.0 million was drawn under this agreement and our proportionate share of the obligation was $95.4 million. The interest rate grid ranges from LIBOR plus 175 bps to 275 bps (or ABR plus 75 bps to 175 bps), depending on the percentages of drawn balances to the borrowing base as defined in the agreement. The borrowing base is redetermined semi-annually, with the EXCO/HGI Partnership and the lenders having the right to request interim unscheduled redeterminations in certain circumstances. The EXCO/HGI Partnership entered into the First Amendment to the EXCO/HGI Partnership Credit Agreement on March 5, 2013, which increased the borrowing base to $470.0 million as a result of the acquisition of the shallow Cotton Valley assets from an affiliate of BG Group. The EXCO/HGI Partnership Credit Agreement matures on February 14, 2018.

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Borrowings under the EXCO/HGI Partnership Credit Agreement are collateralized by first lien mortgages providing a security interest of not less than 80% of the engineered value, as defined in the EXCO/HGI Partnership Credit Agreement, of the oil and natural gas properties evaluated by the lenders for purposes of establishing the borrowing base. The EXCO/HGI Partnership is permitted to have derivative financial instruments covering no more than 100% of the forecasted production from proved developed producing reserves (as defined in the agreement) for any month during the first two years of the forthcoming five year period, 90% of the forecasted production from proved developed producing reserves for any month during the third year of the forthcoming five year period and 85% of the forecasted production from proved developed producing reserves for any month during the fourth and fifth years of the forthcoming five year period.

As of March 31, 2013, the EXCO/HGI Partnership was in compliance with the financial covenants contained in the EXCO/HGI Partnership Credit Agreement, which require that it:

• maintain a consolidated current ratio (as defined in the agreement) of at least 1.0 to 1.0 as of the end of any fiscal quarter; and

• not permit the ratio of consolidated funded indebtedness (as defined in the agreement) to consolidated EBITDAX (as defined in the agreement) to be greater than 4.5 to 1.0 at the end of any fiscal quarter.

The foregoing descriptions are not complete and are qualified in their entirety by the EXCO Resources Credit Agreement, the indenture governing the 2018 Notes and the EXCO/HGI Partnership Credit Agreement.

10.    Dividends

On March 1, 2013, our board of directors approved a cash dividend of $0.05 per share for the first quarter of 2013. The total cash dividend was $10.9 million, of which $10.7 million was paid on March 29, 2013 to holders of record on March 15, 2013 and the remainder was accrued to be paid to restricted shareholders when their shares vest.

Any future declaration of dividends, as well as the establishment of record and payment dates, is subject to limitations under the EXCO Resources Credit Agreement, the indenture governing the 2018 Notes and the approval of our board of directors.

11.    Income taxes

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. We have accumulated financial deferred tax assets primarily due to losses arising from ceiling test write-downs to the carrying value of our oil and natural gas properties that are subject to valuation allowances. Our valuation allowances decreased $72.5 million and increased $106.6 million for the three months ended March 31, 2013 and 2012, respectively. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately $848.0 million as of March 31, 2013. The valuation allowances will continue to be recognized until the realization of future deferred tax benefits are more likely than not to become utilized. The valuation allowance does not impact future utilization of the underlying tax attributes.

12.    Segment information

Our reportable business segments consist of exploration and production and midstream. The exploration and production segment is responsible for acquisition, exploration, exploitation, development and production of oil, natural gas and natural gas liquids. The midstream segment, which consists of TGGT and the Appalachia Midstream JV, is accounted for using the equity method and is responsible for purchasing, gathering, transporting and treating natural gas.

Our management evaluates TGGT and the Appalachia Midstream JV’s performance on a stand-alone basis. The revenues and expenses used to compute the midstream segment's profit represent TGGT and Appalachia Midstream’s results of operations without regard to our 50% ownership. Since we use the equity method of accounting for TGGT, we eliminate these revenues and expenses when reconciling to our consolidated results of operations and report our net share of the midstream segment's operations as equity income (loss). See “Note 13. Equity investments” for additional details related to our equity investments, including our midstream segment.

Summarized financial information concerning our reportable segments is shown in the following table:

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(in thousands)	Exploration and production			Midstream			Equity investee and intercompany eliminations			Consolidated total
For the three months ended March 31, 2013:
Third party revenues	$	138,223		$	56,833		$	(56,833	)	$	138,223
Intersegment revenues	—			—			—			—
Total revenues	$	138,223		$	56,833		$	(56,833	)	$	138,223
Segment profit	$	94,882		$	42,601		$	(42,601	)	$	94,882
Equity income (loss)	$	(549	)	$	13,212		$	—		$	12,663
For the three months ended March 31, 2012:
Third party revenues	$	134,848		$	62,924		$	(62,924	)	$	134,848
Intersegment revenues	—			—			—			—
Total revenues	$	134,848		$	62,924		$	(62,924	)	$	134,848
Segment profit	$	78,436		$	42,321		$	(42,321	)	$	78,436
Equity loss	$	(408	)	$	(7,498	)	$	—		$	(7,906	)
As of March 31, 2013
Capital expenditures	$	69,286		$	6,733		$	(6,733	)	$	69,286
Goodwill	$	163,155		$	—		$	—		$	163,155
Total assets	$	1,890,146		$	1,247,340		$	(1,247,340	)	$	1,890,146
As of December 31, 2012
Capital expenditures	$	501,847		$	134,167		$	(134,167	)	$	501,847
Goodwill	$	218,256		$	—		$	—		$	218,256
Total assets	$	2,323,732		$	1,254,217		$	(1,254,217	)	$	2,323,732

The following table reconciles the segment profits reported above to income (loss) before income taxes:

	Three Months Ended March 31,
(in thousands)	2013			2012
Segment profit	$	94,882		$	78,436
Depletion, depreciation and amortization	(41,308		)	(89,582		)
Write-down of oil and natural gas properties	(10,707		)	(275,864		)
Accretion of discount on asset retirement obligations	(690		)	(947		)
General and administrative	(17,984		)	(21,505		)
Gain (loss) on divestitures and other operating items	184,882			(1,625		)
Interest expense	(20,192		)	(16,764		)
Gain (loss) on derivative financial instruments	(43,514		)	53,865
Other income	88			243
Equity income (loss)	12,663			(7,906		)
Income (loss) before income taxes	$	158,120		$	(281,649	)

13.    Equity investments

We hold equity investments in four entities with BG Group, which are described below. We use the equity method of accounting for each investment.

• We have a 50% ownership in TGGT, which holds interests in midstream assets in East Texas and North Louisiana.

• We own a 50% interest in OPCO, which operates the Appalachia JV properties, subject to oversight from a management board having equal representation from EXCO and BG Group.

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• We own a 50% interest in the Appalachia Midstream JV, through which we and BG Group plan to develop infrastructure and provide take-away capacity in the Marcellus shale.

• We own a 50% interest in an entity that manages certain surface acreage.

The following tables present summarized consolidated financial information of our equity investments and a reconciliation of our investment to our proportionate 50% interest.

(in thousands)	March 31, 2013		December 31, 2012
Assets
Total current assets	$	134,579	$	151,098
Property and equipment, net	1,228,791		1,228,231
Other assets	6,581		6,408
Total assets	$	1,369,951	$	1,385,737
Liabilities and members’ equity
Total current liabilities	$	103,766	$	120,408
Total long term liabilities	468,402		492,071
Members’ equity:
Total members' equity	797,783		773,258
Total liabilities and members’ equity	$	1,369,951	$	1,385,737

	Three Months Ended March 31,
(in thousands)	2013		2012
Revenues:
Oil and natural gas	$	177	$	105
Midstream	56,833		62,924
Total revenues	57,010		63,029
Costs and expenses:
Oil and natural gas production	74		57
Midstream operating	14,232		20,603
Asset impairments, net of insurance recoveries	264		35,343
General and administrative	3,911		7,408
Depletion, depreciation and amortization	11,226		9,302
Other expenses	2,805		6,828
Total costs and expenses	32,512		79,541
Income (loss) before income taxes	24,498		(16,512		)
Income tax expense	110		238
Net income (loss)	$	24,388	$	(16,750	)
EXCO’s share of equity income (loss) before amortization	$	12,194	$	(8,375	)
Amortization of the difference in the historical basis of our contribution	$	469	$	469
EXCO’s share of equity income (loss) after amortization	$	12,663	$	(7,906	)

(in thousands)	March 31, 2013			December 31, 2012
Equity investments	$	359,739		$	347,008
Basis adjustment (1)	45,755			45,755
Cumulative amortization of basis adjustment (2)	(6,602		)	(6,134		)
EXCO’s 50% interest in equity investments	$	398,892		$	386,629

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(1) Our equity in TGGT and OPCO, at inception, exceeded the book value of our investments by an aggregate of $45.8 million, comprised of an aggregate $57.2 million difference in the historical basis of our contribution and the fair value of BG Group’s contribution, offset by $11.4 million of goodwill included in our investment in TGGT.

(2) The aggregate $57.2 million basis difference is being amortized over the estimated life of the associated assets.

14.    Related party transactions

TGGT provides us with gathering, treating and well connect services in the ordinary course of business. In addition, TGGT also purchases natural gas from us in certain areas. OPCO serves as the operator of our wells in the Appalachia JV. There are service agreements between us and TGGT and OPCO whereby we provide administrative and technical services for which we are reimbursed. For the three months ended March 31, 2013 and 2012, these transactions included the following:

	Three Months Ended March 31,
	2013				2012
(in thousands)	TGGT		OPCO		TGGT		OPCO
Amounts paid:
Gathering, treating and well connection fees (1)	$	44,433	$	—	$	54,098	$	—
Advances to operator	—		17,432		—		4,869
Amounts received:
Natural gas purchases	1,648		—		5,107		—
General and administrative services	2,765		9,963		6,014		12,729
Other	35		—		670		—
Total	$	4,448	$	9,963	$	11,791	$	12,729

(1) Represents the gross billings from TGGT.

As of March 31, 2013 and December 31, 2012, the amounts owed under the service agreements were as follows:

	March 31, 2013				December 31, 2012
(in thousands)	TGGT		OPCO		TGGT		OPCO
Amounts due to EXCO	$	3,995	$	3,478	$	2,483	$	2,956
Amounts due from EXCO (1)	13,135		—		12,540		—

(1) OPCO is the operator of our wells in the Appalachia JV and we advance funds to OPCO on an as needed basis, which are included in "Other current assets" on our Condensed Consolidated Balance Sheets. Any amounts we owe are netted against the advance until the advances are utilized. If the advances are fully utilized, we record amounts owed in "Accounts payable and accrued liabilities" on our Condensed Consolidated Balance Sheets.

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15.    Condensed consolidating financial statements

As of March 31, 2013, the majority of EXCO’s subsidiaries were guarantors under the EXCO Resources Credit Agreement and the indenture governing the 2018 Notes. All of our non-guarantor subsidiaries were considered unrestricted subsidiaries under the indenture governing the 2018 Notes, with the exception of our equity investment in OPCO. As of and for the three months ended March 31, 2013:

• Our equity method investment in OPCO represented $16.7 million of equity method investments and contributed $0.6 million of equity method losses; and

• Our interests in jointly held entities with BG Group, with the exception of OPCO, represented $343.0 million of our equity method investments and contributed $13.3 million of our equity method income.

Borrowings under the EXCO/HGI Partnership Credit Agreement are secured by properties owned by the EXCO/HGI Partnership and we do not guarantee the EXCO/HGI Partnership's debt. The EXCO/HGI Partnership is not a guarantor to the EXCO Resources Credit Agreement or the 2018 Notes.

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The 2018 Notes, which were issued by EXCO Resources, Inc., are jointly and severally guaranteed by some of our subsidiaries (referred to as Guarantor Subsidiaries). For purposes of this footnote, EXCO Resources, Inc. is referred to as Resources to distinguish it from the Guarantor Subsidiaries. Each of the Guarantor Subsidiaries are wholly-owned subsidiaries of Resources and the guarantees are unconditional as it relates to the assets of the Guarantor Subsidiaries.

The following financial information presents consolidating financial statements, which include:

• Resources;

• the Guarantor Subsidiaries on a combined basis;

• the Non-Guarantor Subsidiaries;

• elimination entries necessary to consolidate Resources, the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries; and

• EXCO on a consolidated basis.

Investments in subsidiaries are accounted for using the equity method of accounting for the disclosures within this footnote. The financial information for the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries is presented on a combined basis. The elimination entries primarily eliminate investments in subsidiaries and intercompany balances and transactions.

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

(Unaudited)

March 31, 2013

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	35,415		$	(12,577	)	$	3,808		$	—		$	26,646
Restricted cash	—			53,292			—			—			53,292
Other current assets	23,123			162,925			8,077			—			194,125
Total current assets	58,538			203,640			11,885			—			274,063
Equity investments	—			—			359,739			—			359,739
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	85			385,841			4,072			—			389,998
Proved developed and undeveloped oil and natural gas properties	331,931			2,172,964			113,397			—			2,618,292
Accumulated depletion	(329,850		)	(1,653,577		)	(1,129		)	—			(1,984,556		)
Oil and natural gas properties, net	2,166			905,228			116,340			—			1,023,734
Gas gathering, office, field and other equipment, net	6,455			13,602			23,673			—			43,730
Investments in and advances to affiliates, net	1,489,026			—			—			(1,489,026		)	—
Deferred financing costs, net	17,838			—			1,419			—			19,257
Derivative financial instruments	6,365			—			75			—			6,440
Goodwill	13,293			149,862			—			—			163,155
Other assets	1			27			—			—			28
Total assets	$	1,593,682		$	1,272,359		$	513,131		$	(1,489,026	)	$	1,890,146
Liabilities and shareholders' equity
Current liabilities	$	33,586		$	146,181		$	13,191		$	—		$	192,958
Long-term debt	1,236,006			—			95,370			—			1,331,376
Deferred income taxes	—			—			—			—			—
Other long-term liabilities	24,146			33,582			8,140			—			65,868
Payable to parent	—			1,810,599			38,968			(1,849,567		)	—
Total shareholders' equity	299,944			(718,003		)	357,462			360,541			299,944
Total liabilities and shareholders' equity	$	1,593,682		$	1,272,359		$	513,131		$	(1,489,026	)	$	1,890,146

21

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2012

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	65,791		$	(20,147	)	$	—	$	—		$	45,644
Restricted cash	—			70,085			—		—			70,085
Other current assets	63,333			182,804			—		—			246,137
Total current assets	129,124			232,742			—		—			361,866
Equity investments	—			—			347,008		—			347,008
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	48,179			421,864			—		—			470,043
Proved developed and undeveloped oil and natural gas properties	513,668			2,202,099			—		—			2,715,767
Accumulated depletion	(328,560		)	(1,617,005		)	—		—			(1,945,565		)
Oil and natural gas properties, net	233,287			1,006,958			—		—			1,240,245
Gas gathering, office, field and other equipment, net	7,701			109,490			—		—			117,191
Investments in and advances to affiliates, net	1,622,731			—			—		(1,622,731		)	—
Deferred financing costs, net	22,584			—			—		—			22,584
Derivative financial instruments	16,554			—			—		—			16,554
Goodwill	38,100			180,156			—		—			218,256
Other assets	1			27			—		—			28
Total assets	$	2,070,082		$	1,529,373		$	347,008	$	(1,622,731	)	$	2,323,732
Liabilities and shareholders' equity
Current liabilities	$	37,031		$	200,900		$	—	$	—		$	237,931
Long-term debt	1,848,972			—			—		—			1,848,972
Deferred income taxes	—			—			—		—			—
Other long-term liabilities	34,686			52,750			—		—			87,436
Payable to parent	—			2,172,526			—		(2,172,526		)	—
Total shareholders' equity	149,393			(896,803		)	347,008		549,795			149,393
Total liabilities and shareholders' equity	$	2,070,082		$	1,529,373		$	347,008	$	(1,622,731	)	$	2,323,732

22

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended March 31, 2013

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	8,046		$	124,474		$	5,703		$	—		$	138,223
Costs and expenses:
Oil and natural gas production	2,212			14,105			2,548			—			18,865
Gathering and transportation	—			24,007			469			—			24,476
Depletion, depreciation and amortization	2,607			37,528			1,173			—			41,308
Write-down of oil and natural gas properties	—			10,707			—			—			10,707
Accretion of discount on asset retirement obligations	50			549			91			—			690
General and administrative	653			16,963			368			—			17,984
Gain on divestitures and other operating items	(25,974		)	(158,904		)	(4		)	—			(184,882		)
Total costs and expenses	(20,452		)	(55,045		)	4,645			—			(70,852		)
Operating income (loss)	28,498			179,519			1,058			—			209,075
Other income (expense):
Interest expense	(19,877		)	—			(315		)	—			(20,192		)
Loss on derivative financial instruments	(39,802		)	(690		)	(3,022		)	—			(43,514		)
Other income	47			39			2			—			88
Equity income	—			—			12,663			—			12,663
Equity in earnings of subsidiaries	189,254			—			—			(189,254		)	—
Total other income (expense)	129,622			(651		)	9,328			(189,254		)	(50,955		)
Income before income taxes	158,120			178,868			10,386			(189,254		)	158,120
Income tax expense	—			—			—			—			—
Net income	$	158,120		$	178,868		$	10,386		$	(189,254	)	$	158,120

23

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended March 31, 2012

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	23,273		$	111,575		$	—		$	—	$	134,848
Costs and expenses:
Oil and natural gas production	5,125			24,864			—			—		29,989
Gathering and transportation	—			26,423			—			—		26,423
Depletion, depreciation and amortization	(6,892		)	96,474			—			—		89,582
Write-down of oil and natural gas properties	—			275,864			—			—		275,864
Accretion of discount on asset retirement obligations	126			821			—			—		947
General and administrative	3,775			17,730			—			—		21,505
Other operating items	42			1,583			—			—		1,625
Total costs and expenses	2,176			443,759			—			—		445,935
Operating income (loss)	21,097			(332,184		)	—			—		(311,087		)
Other income (expense):
Interest expense	(16,764		)	—			—			—		(16,764		)
Gain on derivative financial instruments	49,223			4,642			—			—		53,865
Other income	36			207			—			—		243
Equity loss	—			—			(7,906		)	—		(7,906		)
Equity in earnings of subsidiaries	(335,241		)	—			—			335,241		—
Total other income (expense)	(302,746		)	4,849			(7,906		)	335,241		29,438
Loss before income taxes	(281,649		)	(327,335		)	(7,906		)	335,241		(281,649		)
Income tax expense	—			—			—			—		—
Net loss	$	(281,649	)	$	(327,335	)	$	(7,906	)	$	335,241	$	(281,649	)

24

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the three months ended March 31, 2013

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by (used in) operating activities	$	(7,339	)	$	49,254		$	1,299		$	—	$	43,214
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment and property acquisitions	(5,567		)	(66,701		)	(34,033		)	—		(106,301		)
Restricted cash	—			16,793			—			—		16,793
Equity method investments	—			(68		)	—			—		(68		)
Proceeds from disposition of property and equipment	244,609			366,594			—			—		611,203
Net changes in advances from Appalachia JV	—			3,633			—			—		3,633
Advances/investments with affiliates	361,935			(361,935		)	—			—		—
Net cash provided by (used in) investing activities	600,977			(41,684		)	(34,033		)	—		525,260
Financing Activities:
Borrowings under credit agreements	10,000			—			36,757			—		46,757
Repayments under credit agreements	(623,266		)	—			—			—		(623,266		)
Proceeds from issuance of common stock	22			—			—			—		22
Payment of common stock dividends	(10,739		)	—			—			—		(10,739		)
Deferred financing costs and other	(31		)	—			(215		)	—		(246		)
Net cash provided by (used in) financing activities	(624,014		)	—			36,542			—		(587,472		)
Net increase (decrease) in cash	(30,376		)	7,570			3,808			—		(18,998		)
Cash at beginning of period	65,791			(20,147		)	—			—		45,644
Cash at end of period	$	35,415		$	(12,577	)	$	3,808		$	—	$	26,646

25

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the three months ended March 31, 2012

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	40,676		$	104,447		$	—	$	—	$	145,123
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment and property acquisitions	(10,120		)	(161,038		)	—		—		(171,158		)
Restricted cash	—			(8,117		)	—		—		(8,117		)
Equity method investments	—			(137		)	—		—		(137		)
Proceeds from disposition of property and equipment	—			981			—		—		981
Net changes in advances from Appalachia JV	—			10,543			—		—		10,543
Advances/investments with affiliates	(78,910		)	78,910			—		—		—
Net cash used in investing activities	(89,030		)	(78,858		)	—		—		(167,888		)
Financing Activities:
Borrowings under credit agreements	53,000			—			—		—		53,000
Repayments under credit agreements	(23,000		)	—			—		—		(23,000		)
Proceeds from issuance of common stock	2			—			—		—		2
Payment of common stock dividends	(8,663		)	—			—		—		(8,663		)
Deferred financing costs and other	—			—			—		—		—
Net cash provided by financing activities	21,339			—			—		—		21,339
Net increase (decrease) in cash	(27,015		)	25,589			—		—		(1,426		)
Cash at beginning of period	78,664			(46,667		)	—		—		31,997
Cash at end of period	$	51,649		$	(21,078	)	$	—	$	—	$	30,571

26

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “EXCO,” “EXCO Resources,” “Company,” “we,” “us,” and “our” are to EXCO Resources, Inc. and its consolidated subsidiaries.

Forward-looking statements

This Quarterly Report on Form 10-Q contains forward-looking statements, as defined in Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. These forward-looking statements relate to, among other things, the following:

• our future financial and operating performance and results;

• our business strategy;

• market prices for oil, natural gas and natural gas liquids;

• our future use of derivative financial instruments; and

• our plans and forecasts.

We have based these forward-looking statements on our current assumptions, expectations and projections about future events.

We use the words “may,” “expect,” “anticipate,” “estimate,” “believe,” “continue,” “intend,” “plan,” “budget” and other similar words to identify forward-looking statements. The statements that contain these words should be read carefully because they discuss future expectations, contain projections of results of operations or our financial condition and/or state other “forward-looking” information. We do not undertake any obligation to update or revise any forward-looking statements, except as required by applicable securities laws. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this Quarterly Report on Form 10-Q, including, but not limited to:

• fluctuations in the prices of oil, natural gas and natural gas liquids;

• the availability of foreign oil, natural gas and natural gas liquids;

• future capital requirements and availability of financing;

• disruption of credit and capital markets and the ability of financial institutions to honor their commitments;

• estimates of reserves and economic assumptions;

• geological concentration of our reserves;

• risks associated with drilling and operating wells;

• exploratory risks, including our Marcellus shale play in Appalachia and the Haynesville/Bossier shale play in East Texas/North Louisiana;

• risks associated with the operation of natural gas pipelines and gathering systems;

• discovery, acquisition, development and replacement of oil and natural gas reserves;

• cash flow and liquidity;

• timing and amount of future production of oil and natural gas;

• availability of drilling and production equipment;

• marketing of oil and natural gas;

• political and economic conditions and events in oil-producing and natural gas-producing countries;

• title to our properties;

• litigation;

• competition;

• general economic conditions, including costs associated with drilling and operation of our properties;

• environmental or other governmental regulations, including legislation to reduce emissions of greenhouse gases, legislation of derivative financial instruments, regulation of hydraulic fracture stimulation and elimination of income tax incentives available to our industry;

• receipt and collectability of amounts owed to us by purchasers of our production and counterparties to our derivative financial instruments;

• decisions whether or not to enter into derivative financial instruments;

• potential acts of terrorism;

• actions of third party co-owners of interests in properties in which we also own an interest;

• fluctuations in interest rates; and

• our ability to effectively integrate companies and properties that we acquire.

27

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. We caution users of the financial statements not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the cautionary statements in this Quarterly Report on Form 10-Q, and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2012, filed with the Securities and Exchange Commission, or the SEC, on February 21, 2013.

Our revenues, operating results and financial condition substantially depend on prevailing prices for oil and natural gas and the availability of capital from our credit agreement, or the EXCO Resources Credit Agreement. Declines in oil or natural gas prices may have a material adverse effect on our financial condition, liquidity, results of operations, the amount of oil or natural gas that we can produce economically and the ability to fund our operations. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

Overview

We are an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and production of onshore U.S. oil and natural gas properties. Our principal operations are conducted in certain key U.S. oil and natural gas areas including East Texas, North Louisiana, Appalachia and the Permian Basin in West Texas. In addition to our oil and natural gas producing operations, we own 50% interests in two midstream joint ventures located in East Texas/North Louisiana and Appalachia.

Our primary strategy includes evaluating acquisitions that meet our strategic and financial objectives, and exploiting our shale resource plays. We plan to carry out this strategy by leveraging our management and technical team's experience, exploiting our multi-year inventory of development drilling locations in our shale plays, actively seeking acquisition opportunities both inside and outside our existing operating areas, managing our liquidity and maintaining financial flexibility. These approaches enhance our ability to execute our business plan over the entire commodity price cycle, protect our returns on investments and manage our capital structure.

Our current acquisition strategy focuses on producing properties with upside development opportunities. These acquisitions are dependent on oil and natural gas prices, availability of producing properties and attractive acreage, acceptable rates of return and availability of borrowing capacity under our credit agreement or from other capital sources. While we expect to continue to evaluate acreage acquisition opportunities in our shale areas, we believe the current depressed natural gas prices provide greater opportunities from producing property acquisitions rather than undeveloped acreage acquisitions.

Like all oil and natural gas exploration and production companies, we face the challenge of natural production declines. Oil and natural gas production from a given well naturally decreases over time. We attempt to offset the impact of this natural decline by drilling to identify and develop additional reserves and adding additional reserves through acquisitions. As a result of our reduced drilling programs in response to low natural gas prices, we expect our production volumes to decline in 2013.

Recent Developments

EXCO/HGI Partnership

On February 14, 2013, we formed a partnership, or the EXCO/HGI Partnership, with Harbinger Group Inc., or HGI. Pursuant to the agreements governing the transaction, we contributed our conventional non-shale assets in East Texas and North Louisiana and our shallow Canyon Sand and other assets in the Permian Basin of West Texas to the EXCO/HGI Partnership in exchange for net proceeds of $573.3 million after customary preliminary purchase price adjustments, and a 25.5% economic interest in the partnership. HGI's economic interest in the EXCO/HGI Partnership is 74.5%. The primary strategy of the EXCO/HGI Partnership is to acquire conventional producing oil and natural gas properties to enhance asset value and cash flow.

Proceeds from the formation of the EXCO/HGI Partnership were used to reduce outstanding borrowings under the EXCO Resources Credit Agreement. As a result of this transaction, our borrowing base under the EXCO Resources Credit Agreement was reduced to $900.0 million.

Immediately following the closing, the EXCO/HGI Partnership entered into an agreement to purchase the shallow Cotton Valley assets within our joint venture with an affiliate of BG Group, plc, or BG Group, for $130.9 million after customary preliminary purchase price adjustments. The assets acquired as a result of this transaction represented an incremental working interest in properties owned by the EXCO/HGI Partnership. The transaction closed on March 5, 2013 and was funded with borrowings from the EXCO/HGI Partnership's credit agreement, or the EXCO/HGI Partnership Credit Agreement.

28

Acreage transaction

On March 13, 2013, we closed a sale and joint development agreement with a private party for the sale of an undivided 50% of our interest in certain undeveloped acreage. We received $37.9 million in cash, after final closing adjustments. In addition to the cash consideration received at closing, the purchaser agreed to fund our share of drilling and completion costs within the joint venture area up to $18.9 million, with any remaining unfunded amount paid to us by June 30, 2016.

Critical accounting policies

We consider accounting policies related to our estimates of proved reserves, accounting for derivatives, business combinations, share-based payments, oil and natural gas properties, goodwill, revenue recognition, asset retirement obligations and income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC on February 21, 2013.

29

Our results of operations

A summary of key financial data for the three months ended March 31, 2013 and 2012 related to our results of operations is presented below:

	Three Months Ended March 31,						Quarter to quarter change
(dollars in thousands, except per unit prices)	2013			2012
Production:
Oil (Mbbls)	102			192			(90		)
Natural gas liquids (Mbbls)	82			122			(40		)
Natural gas (Mmcf)	39,593			46,992			(7,399		)
Total production (Mmcfe) (1)	40,697			48,876			(8,179		)
Average daily production (Mmcfe)	452			537			(85		)
Revenues before derivative financial instrument activities:
Oil	$	8,334		$	18,650		$	(10,316	)
Natural gas liquids	3,093			6,454			(3,361		)
Natural gas	126,796			109,744			17,052
Total revenues	$	138,223		$	134,848		$	3,375
Oil and natural gas derivative financial instruments:
Cash settlements on derivative financial instruments	$	16,718		$	50,145		$	(33,427	)
Non-cash change in fair value of derivative financial instruments	(60,232		)	3,720			(63,952		)
Total derivative financial instrument activities	$	(43,514	)	$	53,865		$	(97,379	)
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)	$	81.71		$	97.14		$	(15.43	)
Natural gas liquids (per Bbl)	37.72			52.90			(15.18		)
Natural gas (per Mcf)	3.20			2.34			0.86
Natural gas equivalent (per Mcfe)	3.40			2.76			0.64
Costs and expenses:
Oil and natural gas operating costs	$	13,617		$	22,796		$	(9,179	)
Production and ad valorem taxes	5,248			7,193			(1,945		)
Gathering and transportation	24,476			26,423			(1,947		)
Depletion	38,991			85,516			(46,525		)
Depreciation and amortization	2,317			4,066			(1,749		)
General and administrative (2)	17,984			21,505			(3,521		)
Interest expense	20,192			16,764			3,428
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.33		$	0.47		$	(0.14	)
Production and ad valorem taxes	0.13			0.15			(0.02		)
Gathering and transportation	0.60			0.54			0.06
Depletion	0.96			1.75			(0.79		)
Depreciation and amortization	0.06			0.08			(0.02		)
General and administrative	0.44			0.44			—
Net income (loss)	$	158,120		$	(281,649	)	$	439,769

(1) Mmcfe is calculated by converting one barrel of oil or natural gas liquids into six Mcf of natural gas.

(2) Share-based compensation expense included in general and administrative expenses was $1.7 million and $2.9 million for the three months ended March 31, 2013 and 2012, respectively.

Following is a discussion of our financial condition and results of operations for the three months ended March 31, 2013 and 2012. The comparability of our results of operations from period to period was impacted by:

30

• the formation of the EXCO/HGI Partnership in the first quarter of 2013;

• fluctuations in oil, natural gas and natural gas liquids prices, which impact our oil and natural gas reserves, revenues, cash flows and net income or loss;

• ceiling test write-downs in 2013 and 2012;

• asset impairments and other non-recurring costs;

• mark-to-market gains and losses from our derivative financial instruments;

• changes in proved reserves and production volumes and their impact on depletion;

• the impact of declining natural gas production volumes from our significantly reduced horizontal drilling activities in the Haynesville/Bossier and Marcellus shales; and

• significant changes in the amount of our long-term debt.

In the second quarter of 2012, we began reporting our natural gas liquids production separately from our natural gas production. We have recast prior periods to conform to this presentation.

General

The availability of a ready market and prices for oil, natural gas and natural gas liquids are dependent upon a number of factors that are beyond our control. These factors include, among other things:

• the level of domestic production and economic activity;

• the domestic oversupply of natural gas;

• the inability to export domestic oil, natural gas and natural gas liquids;

• the level of domestic and industrial demand for natural gas for utilities and manufacturing operations;

• the available capacity at natural gas storage facilities and quantities of inventories in storage;

• the availability of imported oil and natural gas;

• actions taken by foreign oil producing nations;

• the cost and availability of natural gas pipelines with adequate capacity and other transportation facilities;

• the cost and availability of other competitive fuels;

• fluctuating and seasonal demand for oil, natural gas, natural gas liquids and refined products;

• the extent of governmental regulation and taxation (under both present and future legislation) of the exploration, production, refining, transportation, pricing, use and allocation of oil, natural gas, refined products and substitute fuels; and

• trends in fuel use and government regulations that encourage less fuel use and encourage or mandate alternative fuel use.

Accordingly, in light of the many uncertainties affecting the supply and demand for oil, natural gas, natural gas liquids and refined petroleum products, we cannot accurately predict the prices or marketability of oil, natural gas and natural gas liquids from any producing well in which we have or may acquire an interest.

Marketing arrangements

We produce oil, natural gas and natural gas liquids. We do not refine or process the oil, natural gas or natural gas liquids we produce. We sell the majority of the oil we produce under short-term contracts using market sensitive pricing. The majority of our contracts are based on NYMEX pricing, which is typically calculated as the average of the daily closing prices of oil to be delivered one month in the future. We also sell a portion of our oil at F.O.B. field prices posted by the principal purchaser of oil where our producing properties are located. Our sales contracts are of a type common within the industry, and we usually negotiate a separate contract for each property. Generally, we sell our oil to purchasers and refiners near the areas of our producing properties.

We sell the majority of our natural gas under individually negotiated gas purchase contracts using market sensitive pricing. Our sales contracts vary in length from spot market sales of a single day to term agreements that may extend for a year or more. Our natural gas customers include utilities, natural gas marketing companies and a variety of commercial and industrial end users. The natural gas purchase contracts define the terms and conditions unique to each of these sales. The price received for natural gas sold on the spot market varies daily, reflecting changing market conditions. Some of our natural gas is sold under contracts which provide for sharing in a percentage of proceeds of natural gas liquids extracted by third party plants.

We may be unable to market all of the oil and natural gas we produce. If our oil and natural gas can be marketed, we may be unable to negotiate favorable pricing and contractual terms. Changes in oil or natural gas prices may significantly affect our revenues, cash flows, the value of our oil and natural gas properties and the estimates of recoverable oil and natural gas reserves. Further, significant declines in the prices of oil or natural gas may have a material adverse effect on our business and on our financial condition.

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We engage in oil and natural gas production activities in geographic regions where, from time to time, the supply of oil or natural gas available for delivery exceeds the demand. If this occurs, companies purchasing oil or natural gas in these areas may reduce the amount of oil or natural gas that they purchase from us. If we cannot locate other buyers for our production or for any of our oil or natural gas reserves, we may shut in our oil or natural gas wells for certain periods of time. If this occurs, we may incur additional payment obligations under our oil and natural gas leases and, under certain circumstances, the oil and natural gas leases might be terminated. Economic conditions, particularly low natural gas prices, may negatively impact the liquidity and creditworthiness of our purchasers and may expose us to risk with respect to the ability to collect payments for the oil and natural gas we deliver.

Summary

For the three months endedMarch 31, 2013, we reported net income of $158.1 million compared to a net loss of $281.6 million for the three months ended March 31, 2012. The net income for the three months ended March 31, 2013 was primarily the result of the gain on the divestiture of certain oil and natural gas properties in connection with the formation of the EXCO/HGI Partnership. Average natural gas equivalent prices for the three months ended March 31, 2013 averaged $3.40 per Mcfe, compared with average natural gas equivalent prices for the three months ended March 31, 2012 of $2.76 per Mcfe.

We use oil and natural gas swap and call option contracts to manage our exposure to commodity price fluctuations, protect our returns on investments and achieve a more predictable cash flow from our operations. We do not designate our derivative financial instruments as hedges. As a result, we mark non-cash changes in the fair value of unsettled derivative financial instruments to market at the end of each reporting period and recognize the change in our results of operations. The impacts of realized and unrealized changes in the fair value of derivative financial instruments resulted in a net loss of $43.5 million and a net gain of $53.9 millionfor the three months ended March 31, 2013 and 2012, respectively.

Presentation of results of operations as a result of the formation of the EXCO/HGI Partnership

Our discussion of production, revenues and direct operating expenses is based on our producing regions and the EXCO/HGI Partnership. The EXCO/HGI Partnership includes conventional non-shale assets in East Texas, North Louisiana and the Permian Basin. Prior to the formation of the EXCO/HGI Partnership on February 14, 2013, the operating results of the properties contributed by EXCO were included within the "East Texas/North Louisiana" and "Permian and other" regions within our discussion of production, revenues and direct operating expenses. The operating results of the EXCO/HGI Partnership represent our proportionate interest subsequent to the formation on February 14, 2013.

Oil and natural gas production, revenues, and prices

We are presenting the following table to provide a more meaningful analysis of on-going production activity as result of the formation of the EXCO/HGI Partnership. These pro forma adjustments reflect the contribution of properties by EXCO in connection with the formation of the EXCO/HGI Partnership and includes the EXCO/HGI Partnership's acquisition of shallow Cotton Valley assets from an affiliate of BG Group. The pro forma adjustments below reflect our production as if the formation of the EXCO/HGI Partnership and acquisition of the Cotton Valley assets had occurred on January 1, 2012.

	Three Months Ended March 31,
	2013				2012				Quarter to quarter change
(in Mmcfe)	Production	Pro forma adjustments		Pro forma production	Production	Pro forma adjustments		Pro forma production	Production		Pro forma production
Producing region:
East Texas/North Louisiana	33,449	(3,094	)	30,355	42,943	(7,464	)	35,479	(9,494	)	(5,124	)
Appalachia	5,066	—		5,066	3,645	—		3,645	1,421		1,421
Permian and other	1,003	(972	)	31	2,288	(2,223	)	65	(1,285	)	(34	)
EXCO/HGI Partnership	1,179	1,361		2,540	—	3,081		3,081	1,179		(541	)
Total	40,697	(2,705	)	37,992	48,876	(6,606	)	42,270	(8,179	)	(4,278	)

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The following table presents our production, revenue and average sales prices for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013					2012					Quarter to quarter change
(dollars in thousands, except per unit rate)	Production (Mmcfe)	Revenue		$/Mcfe		Production (Mmcfe)	Revenue		$/Mcfe		Production (Mmcfe)		Revenue			$/Mcfe
Producing region:
East Texas/North Louisiana	33,449	$	106,787	$	3.19	42,943	$	101,077	$	2.35	(9,494	)	$	5,710		$	0.84
Appalachia	5,066	17,687		3.49		3,645	10,498		2.88		1,421		7,189			0.61
Permian and other	1,003	8,046		8.02		2,288	23,273		10.17		(1,285	)	(15,227		)	(2.15		)
EXCO/HGI Partnership	1,179	5,703		4.84		—	—		—		1,179		5,703			4.84
Total	40,697	$	138,223	$	3.40	48,876	$	134,848	$	2.76	(8,179	)	$	3,375		$	0.64

Production in our East Texas/North Louisiana region for the three months ended March 31, 2013decreased by 9.5 Bcfe from the comparable period in the prior year. This decrease was primarily the result of the contribution of properties to the EXCO/HGI Partnership along with normal declines in producing wells. During the three months ended March 31, 2013, we operated three horizontal rigs in the East Texas/North Louisiana region, as compared to an average of 14 rigs during the three months ended March 31, 2012. The largest decrease in production occurred in our Vernon field and other shallow conventional wells in the region, which included a decrease in production of 1.5 Bcfe as a result of the contribution of these properties to the EXCO/HGI Partnership and a decrease in production of 0.9 Bcfe due to normal production declines. The increase in production of 1.4 Bcfe in Appalachia was a result of our drilling in the Marcellus shale and completion activities which resulted in 41 additional wells coming on-line subsequent to March 31, 2012. The decrease in production in the Permian and other region was as a result of normal production declines excluding the impact of the contribution of these properties to the EXCO/HGI Partnership. The production of the EXCO/HGI Partnership was positively impacted by 0.2 Bcfe as a result of the acquisition of the Cotton Valley assets from the BG Group on March 5, 2013.

For the three months ended March 31, 2013, oil and natural gas revenues were $138.2 million, a 2.5%increase from the oil and natural gas revenues of $134.8 million for the three months ended March 31, 2012. The increase in revenues was primarily the result of an increase in natural gas prices, which was partially offset by the contribution of properties to the EXCO/HGI Partnership and normal production declines. Our average natural gas sales price, excluding the impact of derivative financial instruments, was $3.20 per Mcf for the three months ended March 31, 2013 compared with $2.34 per Mcf for the three months ended March 31, 2012, an increase of 36.8%. Our average sales price of oil per Bbl, excluding the impact of derivative financial instruments, decreased15.9% to $81.71 per Bbl for the three months ended March 31, 2013 from $97.14 per Bbl for the three months ended March 31, 2012. The significant decrease in the oil price during the first quarter of 2013 was the result of a temporary widening of basis differentials between the WTI Midland pricing, where the majority of our oil is produced and sold, and WTI Cushing. The basis differential was primarily the result of high inventories in January and February 2013 held by regional refiners in the Permian area. The basis differentials have subsequently narrowed closer to historical levels. Our average sales price of natural gas liquids per Bbl decreased28.7% to $37.72 per Bbl for the three months ended March 31, 2013 from $52.90 per Bbl for the three months ended March 31, 2012.

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Oil and natural gas operating costs

The following tables present our operating costs for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013						2012						Quarter to quarter change
(in thousands)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
East Texas/North Louisiana	$	5,407	$	1,595	$	7,002	$	11,301	$	3,810	$	15,111	$	(5,894	)	$	(2,215	)	$	(8,109	)
Appalachia	3,278		—		3,278		4,410		—		4,410		(1,132		)	—			(1,132		)
Permian and other	1,460		—		1,460		3,155		120		3,275		(1,695		)	(120		)	(1,815		)
EXCO/HGI Partnership	1,652		225		1,877		—		—		—		1,652			225			1,877
Total	$	11,797	$	1,820	$	13,617	$	18,866	$	3,930	$	22,796	$	(7,069	)	$	(2,110	)	$	(9,179	)
	Three Months Ended March 31,
	2013						2012						Quarter to quarter change
(per Mcfe)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
East Texas/North Louisiana	$	0.16	$	0.05	$	0.21	$	0.26	$	0.09	$	0.35	$	(0.10	)	$	(0.04	)	$	(0.14	)
Appalachia	0.65		—		0.65		1.21		—		1.21		(0.56		)	—			(0.56		)
Permian and other	1.46		—		1.46		1.38		0.05		1.43		0.08			(0.05		)	0.03
EXCO/HGI Partnership	1.40		0.19		1.59		—		—		—		1.40			0.19			1.59
Operating costs per Mcfe	$	0.29	$	0.04	$	0.33	$	0.39	$	0.08	$	0.47	$	(0.10	)	$	(0.04	)	$	(0.14	)

Our oil and natural gas operating costs for the three months ended March 31, 2013 were $13.6 million compared with $22.8 millionfor the three months ended March 31, 2012. The decrease for the three months ended March 31, 2013 compared to the same period in the prior year was primarily due to the contribution of properties to the EXCO/HGI Partnership and the implementation of cost saving initiatives throughout our organization.

As shown in the tables above, on a per Mcfe basis, oil and natural gas operating costs for the three months ended March 31, 2013decreased$0.14 per Mcfe, a decrease of 29.8%, from the same period in 2012. The net decrease in oil and natural gas operating costs per Mcfe was primarily due to the implementation of numerous cost savings initiatives. Examples of these actions include shutting in marginal producing wells with high-cost water production, decreased compression expenditures and modification of our chemical treating programs. These decreases were partially offset by increases per Mcfe in the Permian region due to higher costs associated with oil and natural gas liquid production.

Midstream operations

We own a 50% equity interest in TGGT Holdings, LLC, or TGGT, and the Appalachia Midstream JV, which provide midstream services to our joint ventures and natural gas producers. Our midstream operations earn fees from the gathering, treating and compression of natural gas. Additional operating margins are derived from the purchase and resale of natural gas to third parties. Our midstream joint ventures do not own any natural gas processing facilities. We use the equity method of accounting for both of our midstream joint ventures.

TGGT holds most of our East Texas/North Louisiana midstream assets. TGGT's operations are principally designed to facilitate the delivery of natural gas produced in the East Texas/North Louisiana region to market. TGGT's primary customers are EXCO and BG Group. The assets of TGGT include treating facilities and gathering pipelines that connect to downstream pipelines.

TGGT operates amine, glycol, and H2S treating facilities, which treat natural gas to meet pipeline specifications for downstream transportation. TGGT’s system, which has access to 17 interstate and intrastate pipeline markets, has approximately 127 miles of pipeline comprised of 12, 16, and 20-inch diameter pipe in the East Texas area and 27 miles of pipeline comprised of 36-inch diameter pipe in the North Louisiana area. The system in the Shelby Area has approximately 115

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miles of operational pipeline comprised of 4-inch to 36-inch diameter pipe servicing Haynesville/Bossier production companies.

TGGTowns and operates a network of gas gathering systems comprised of approximately 800 miles of pipeline located in East Texas and North Louisiana as of March 31, 2013. These gathering pipelines primarily service Cotton Valley production in East Texas/North Louisiana and Haynesville/Bossier production in North Louisiana. Approximately 290 miles of TGGT's gathering lines are located in the core area of the Haynesville/Bossier shale in North Louisiana. Natural gas is gathered through fixed fee arrangements pursuant to which the fee income represents an agreed rate per unit of throughput. The revenues earned from these arrangements are directly related to the volume of natural gas that flows through the systems and are not directly dependent on commodity prices.

In the first quarter of 2013, TGGT continued to significantly reduce its operating expenses through an effective asset optimization program. In addition, capital expenditures decreased from $69.1 million during the three months ended March 31, 2012 to $7.0 million during the three months ended March 31, 2013, primarily due to the completion of major treating projects in 2012 and reductions in drilling activity in 2013. While throughput in the first quarter of 2013 was similar to the fourth quarter of 2012, we expect throughput to decline in the second half of 2013 due to normal production declines and reduced drilling activity in the Haynesville shale.

The Appalachia Midstream JV continues to operate gathering systems and compression facilities to support our development drilling program in the Appalachia JV.

Gathering and transportation

Gathering and transportation expenses totaled $24.5 million or $0.60 per Mcfe for the three months ended March 31, 2013, compared to $26.4 million or $0.54 per Mcfe for the three months ended March 31, 2012. The increase in gathering and transportation expense on a per Mcfe rate is primarily due to lower production and fixed costs associated with firm transportation.

We have entered into firm transportation agreements with pipeline companies to facilitate sales of our Haynesville volumes and report these firm transportation costs as a component of gathering and transportation expenses. As of March 31, 2013, our firm transportation agreements cover an average of 810 Mmcf per day through 2015, with average annual minimum gathering and transportation expenses of approximately $92.5 million per year. These firm transportation agreements cover an average of 738 Mmcf per day in 2016 and trend down to 400 Mmcf per day in 2021, with average annual minimum gathering and transportation expenses of approximately $89.5 million per year in 2016 which trend down to $48.9 million in 2021.

Production and ad valorem taxes

The following table presents our production and ad valorem taxes on a per Mcfe basis and percentage of revenue basis for the three months ended March 31, 2013 and 2012. Overall, our production and ad valorem tax rates per Mcfe were $0.13 per Mcfe for the three months ended March 31, 2013 compared with $0.15 per Mcfe for the three months ended March 31, 2012.

	Three Months Ended March 31,
	2013						2012
(in thousands, except per unit rate)	Production and ad valorem taxes		% of revenue		Taxes $/Mcfe		Production and ad valorem taxes		% of revenue		Taxes $/Mcfe
Producing region:
East Texas/North Louisiana	$	3,150	2.9	%	$	0.09	$	4,469	4.4	%	$	0.10
Appalachia	675		3.8	%	0.13		874		8.3	%	0.24
Permian and other	752		9.3	%	0.75		1,850		7.9	%	0.81
EXCO/HGI Partnership	671		11.8	%	0.57		—		—	%	—
Total	$	5,248	3.8	%	$	0.13	$	7,193	5.3	%	$	0.15

For the three months ended March 31, 2013, production and ad valorem taxes decreased by $1.9 million compared to the same period in 2012. On a percentage of revenue basis, production and ad valorem taxes were 3.8% of oil and natural gas revenues for the three months ended March 31, 2013 compared to 5.3% for the three months ended March 31, 2012.

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In our East Texas/North Louisiana area, we are presently receiving severance tax holidays on certain Haynesville shale wells which reduce the effective rate of these taxes. During the three months ended March 31, 2013 and 2012, wells that did not have a severance tax holiday were charged a severance tax rate of $0.148 per Mcf and $0.164 per Mcf, respectively.

In February 2012, the Commonwealth of Pennsylvania enacted a comprehensive reform to Pennsylvania’s Oil and Gas Act, or the Act, which requires an impact fee to be paid on all unconventional wells spud. The fees will range from $190,000 to $355,000 per well, based on a price tier calculation to be paid annually up to 15 years. The fee is payable for all wells spud in a single year by April 1st of the following year. The Act contained a retroactive fee to be assessed on all unconventional wells spud prior to December 31, 2011. Our retroactive fee of $2.0 million was paid in September 2012, and recorded in “(Gain) loss on divestitures and other operating items” on our Condensed Consolidated Statement of Operations for the three months ended March 31, 2012. The estimated on-going fee, which is recorded in Production and ad valorem taxes on the Condensed Consolidated Statement of Operations, is computed using the prior year’s trailing 12 month NYMEX natural gas price based on a tiered pricing system and will be paid annually for 15 years. For the three months endedMarch 31, 2013 and 2012, we recorded $0.4 million and $0.5 million, respectively, for our estimated impact fees. The production and ad valorem taxes decreased on per Mcfe basis due to higher production and less wells spud during the current year in the Appalachia region.

Production taxes are set by state and local governments and vary as to the tax rate and the value to which that rate is applied. Ad valorem tax rates also vary widely. In Louisiana, where a substantial percentage of our production is derived, production taxes are levied on a per Mcf basis. Therefore, the resulting dollar value of production is not sensitive to changes in prices for natural gas, except for holiday exemptions, if any. In our other operating areas, particularly Texas, production taxes are based on a fixed percentage of gross value of products sold. While severance tax holidays are available in Texas as our production increases, our realized production and ad valorem tax rates may become more sensitive to prices.

Depletion, depreciation and amortization

Our depletion expense for the three months ended March 31, 2013decreased by $46.5 million compared to the same period in 2012. The decrease is primarily the result of lower volumes due to the contribution of properties to the EXCO/HGI Partnership, and ceiling test write-downs which lowered our depletable base. On a per Mcfe basis, our depletion rate for the three months ended March 31, 2013 was $0.96 compared with $1.75 for the comparable period in 2012.

Our depreciation and amortization costs for the three months ended March 31, 2013decreased by $1.7 million, or 43.0%, compared to the same period in 2012. The decrease was due to contribution of gas gathering assets to the EXCO/HGI Partnership.

Accretion of discount on asset retirement obligations for the three months ended March 31, 2013 was $0.7 million compared with $0.9 millionfor the three months ended March 31, 2012. The slight decrease was a result of the contribution of properties to the EXCO/HGI Partnership.

Write-down of oil and natural gas properties

For the three months endedMarch 31, 2013, we recognized a pre-tax ceiling test write-down of $10.7 million primarily due to continued depressed natural gas prices, and a slight decrease in oil and natural gas liquid prices compared to year-end. For the three months ended March 31, 2012, we recognized a pre-tax ceiling test write-down of $275.9 million due primarily to low natural gas prices.

The ceiling test computation is based on the arithmetic average of reference prices on the first day of the month for the 12 months preceding each balance sheet date. If natural gas prices significantly decrease in 2013, we may incur additional ceiling test write-downs.

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General and administrative

The following table presents our general and administrative expenses for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
(in thousands, except per unit rate)	2013			2012			Quarter to quarter change
General and administrative costs:
Gross general and administrative expense	$	32,131		$	40,480		$	(8,349	)
Technical services and service agreement charges	(6,335		)	(7,304		)	969
Operator overhead reimbursements	(3,099		)	(5,240		)	2,141
Capitalized salaries and share-based compensation	(4,713		)	(6,431		)	1,718
General and administrative expense	$	17,984		$	21,505		$	(3,521	)
General and administrative expense per Mcfe	$	0.44		$	0.44		$	—

Our general and administrative costs for the three months ended March 31, 2013 were $18.0 million, or $0.44 per Mcfe, compared to $21.5 million, or $0.44 per Mcfe, for the same period in 2012.

Significant components of the net decrease in general and administrative expense for the three months ended March 31, 2013 compared to the respective 2012 period were a result of:

• decreased personnel costs of $5.8 million primarily related to a reduction in employee headcount and contract labor costs;

• decreased share based compensation expense of $1.5 million due to a reduction in employee headcount and lower expenses associated with the recognition of recent share based payment grants compared to prior years; and

• decreased various other expenses of $0.7 million primarily related to our emphasis on costs reduction including office related expenses, legal costs, travel costs, and meals and entertainment.

The above decreases were partially offset by:

• decreased overhead recoveries of $2.1 million arising from reductions in our drilling program;

• decreased capitalized salaries and share based compensation of $1.7 million as a result of a reduction in employee headcount; and

• decreased technical service recoveries of $1.0 million arising from decreased employee costs.

(Gain) loss on divestitures and other operating items

Our (gain) loss on divestitures and other operating items for the three months ended March 31, 2013 was a net gain of $184.9 million compared with an expense of $1.6 millionfor the three months ended March 31, 2012. The amount for the three months ended March 31, 2013 was primarily related to the gain of $187.0 million as a result of the contribution of certain oil and natural gas properties to the EXCO/HGI Partnership. Partially offsetting the gain were expenses incurred in various legal settlements, losses related to equipment sales and the recovery of royalty payments. The (gain) loss on divestitures and other operating items was a net loss of $1.6 million for the three months ended March 31, 2012, which was primarily related to the $2.0 million retroactive Pennsylvania impact fee discussed in Production and ad valorem taxes. We elected to report the retroactive portion of the Pennsylvania impact fee as a component of other operating items as the retroactive amount would disproportionately impact comparative periods.

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Interest Expense

The following table presents our interest expense for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
(in thousands)	2013			2012			Quarter to quarter change
Interest expense:
2018 Notes	$	14,363		$	14,340		$	23
EXCO Resources Credit Agreement	5,714			7,204			(1,490		)
EXCO/HGI Partnership Credit Agreement	322			—			322
Amortization and write-off of deferred financing costs	4,813			1,472			3,341
Capitalized interest	(5,079		)	(6,302		)	1,223
Other	59			50			9
Total interest expense	$	20,192		$	16,764		$	3,428

Our interest expense for the three months ended March 31, 2013increased$3.4 million from the comparable period in 2012. The increase was primarily due to the acceleration of deferred financing costs of $3.5 million associated with the reduction of our borrowing base as a result of the EXCO/HGI Partnership formation, and decreased capitalized interest related to lower values of unproved oil and natural gas properties. This was partially offset by the reduction in interest expense related to the EXCO Resources Credit Agreement as a result of repayment of indebtedness during the period.

Derivative financial instruments

We enter into derivative financial instruments to manage our exposure to commodity prices, protect our returns on investments, and achieve a more predictable cash flow from operations. These transactions limit exposure to declines in commodity prices, but also limit the benefits we would realize if commodity prices increase. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expenses due to changes in the fair value of our derivative financial instruments. Cash charges or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration. We expect that our revenues will continue to be significantly impacted in future periods by changes in the value of our derivative financial instruments as a result of volatility in oil and natural gas prices and the amount of future production volumes subject to derivative financial instruments.

The following table presents our realized and unrealized gains and losses from our oil and natural gas derivative financial instruments. Our derivative activity is reported as a component of "Other income (expense)" in our Condensed Consolidated Statements of Operations.

	Three Months Ended March 31,
(in thousands)	2013			2012		Quarter to quarter change
Derivative financial instrument activities:
Cash settlements on derivative financial instruments	$	16,718		$	50,145	$	(33,427	)
Non-cash change in fair value of derivative financial instruments	(60,232		)	3,720		(63,952		)
Total derivative financial instrument activities	$	(43,514	)	$	53,865	$	(97,379	)

The following table presents our natural gas prices, before and after the impact of the cash settlement of our derivative financial instruments:

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	Three Months Ended March 31,
Average realized pricing:	2013		2012		Quarter to quarter change
Oil per Bbl	$	81.71	$	97.14	$	(15.43	)
Natural gas liquids per Bbl	37.72		52.90		(15.18		)
Natural gas per Mcf	3.20		2.34		0.86
Natural gas equivalent per Mcfe	3.40		2.76		0.64
Cash settlements on derivative financial instruments, per Mcfe	0.41		1.03		(0.62		)
Net price per Mcfe, including derivative financial instruments	$	3.81	$	3.79	$	0.02

Our total cash settlements on derivative financial instruments were $16.7 million, or $0.41 per Mcfe for the three months ended March 31, 2013, compared to cash settlements of $50.1 million, or $1.03 per Mcfe for the same period in 2012. The significant fluctuations between settlements on our derivative financial instruments demonstrate volatility in commodity prices.

Our non-cash mark-to-market changes in the value of our oil and natural gas derivative financial instruments for the three months ended March 31, 2013 resulted in losses of $60.2 million compared to gains of $3.7 million for the same period in the prior year. The significant fluctuations were also attributable to high volatility in oil and natural gas prices between each of the periods. The ultimate settlement amount of the unrealized portion of the derivative financial instruments is dependent on future commodity prices.

We expect to continue our comprehensive derivative financial instrument program as part of our overall business strategy to enhance our ability to execute our business plan over the entire commodity price cycle, protect our return on investments and manage our capital structure.

Income taxes

Our effective income tax rate for the three months ended March 31, 2013 and 2012 was zero, primarily due to losses arising from ceiling test write-downs, which created deferred tax assets. These deferred tax assets have been fully reserved with valuation allowances. Our accumulated valuation allowance as of March 31, 2013 was approximately $848.0 million and can be used against future deferred financial income. We will continue to recognize deferred tax valuation allowances until the realization of deferred benefits become more likely than not. The effective income tax rates, excluding the impact of the valuation allowances, would have been 45.8%for the three months ended March 31, 2013 and 37.9%for the three months ended March 31, 2012.

Selected EXCO/HGI Partnership information

As discussed in "Note 3. Divestitures, acquisitions and other significant events" in the Notes to our Condensed Consolidated Financial Statements, the EXCO/HGI Partnership was formed on February 14, 2013, which resulted in the reduction of our economic interest in certain oil and natural gas properties contributed to the partnership. On March 5, 2013, the EXCO/HGI Partnership purchased the remaining shallow Cotton Valley assets in the East Texas/North Louisiana JV from an affiliate of BG Group. The following table presents selected pro forma operating and financial information for the three months ended March 31, 2013 and 2012 as if these transactions occurred on January 1, 2012:

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	Three Months Ended March 31,
	2013							2012
(dollars in thousands, except per unit rate)	Historical EXCO		Pro forma adjustments			Pro forma EXCO		Historical EXCO		Pro forma adjustments			Pro forma EXCO
Production:
Total production (Mmcfe)	40,697		(2,705		)	37,992		48,876		(6,606		)	42,270
Average production (Mmcfe/d)	452		(30		)	422		537		(73		)	464
Revenues:
Revenues, excluding derivatives	$	138,223	$	(12,657	)	$	125,566	$	134,848	$	(30,758	)	$	104,090
Average realized price ($/Mcfe)	3.40		4.68			3.31		2.76		4.66			2.46
Expenses:
Direct operating costs	13,617		(3,489		)	10,128		22,796		(8,420		)	14,376
Per Mcfe	0.33		1.29			0.27		0.47		1.27			0.34
Production and ad valorem taxes	5,248		(1,545		)	3,703		7,193		(3,531		)	3,662
Per Mcfe	0.13		0.57			0.10		0.15		0.53			0.09
Gathering and transportation	24,476		(782		)	23,694		26,423		(2,502		)	23,921
Per Mcfe	0.60		0.29			0.62		0.54		0.38			0.57
Excess of revenues over operating expenses	$	94,882	$	(6,841	)	$	88,041	$	78,436	$	(16,305	)	$	62,131

The pro forma information is not necessarily indicative of what actually would have occurred if the transaction had been completed as of January 1, 2012, nor is it necessarily indicative of future consolidated results.

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Our liquidity, capital resources and capital commitments

Overview

Our primary sources of capital resources and liquidity are internally generated cash flows from operations, borrowing capacity under the EXCO Resources Credit Agreement, dispositions of non-strategic assets, joint ventures and capital markets when conditions are favorable. As a result of the depressed natural gas price environment, our 2013 capital budget is designed to limit capital expenditures to approximate our expected cash flows from operations. Other factors that could impact our liquidity, capital resources and capital commitments in 2013 and future years include the following:

• the level of planned drilling activities;

• the results of our ongoing drilling programs;

• our ability to fund or finance acquisitions of oil and natural gas properties;

• our ability to reduce and maintain lower operating, general and administrative expenses and capital expenditure programs in response to continued low natural gas prices;

• reduced oil and natural gas revenues resulting from, among other things, depressed natural gas prices and lower production from reductions to our drilling and development activities;

• our ability to mitigate commodity price volatility with derivative financial instruments;

• potential acquisitions and/or sales of oil and natural gas properties or other assets;

• reductions to our borrowing base; and

• our ability to maintain compliance with debt covenants as a result of depressed natural gas prices.

Recent events affecting liquidity

Upon the formation of the EXCO/HGI Partnership on February 14, 2013, we received net proceeds of $573.3 million, after customary preliminary purchase price adjustments. We used the proceeds to reduce outstanding borrowings under the EXCO Resources Credit Agreement. As a result of this transaction, our borrowing base under the EXCO Resources Credit Agreement was reduced to $900.0 million. The EXCO/HGI Partnership plans on funding their operations with internally generated cash flows and borrowings under the EXCO/HGI Partnership Credit Agreement. In addition, we utilized cash flows from operations and other divestitures in order to reduce outstanding borrowings under the EXCO Resources Credit Agreement by an additional $40.0 million during the three months ended March 31, 2013.

During the first quarter of 2013, prices of natural gas rose modestly which offset lower volumes as a result of the contribution of properties to the EXCO/HGI Partnership and normal production declines. While we believe that our capital resources from existing cash balances, anticipated cash flow from operating activities and available borrowing capacity under the EXCO Resources Credit Agreement will be adequate to execute our corporate strategies and to meet debt service obligations, we are managing 2013 with expectations that natural gas markets will continue to experience an extended period of low prices due to excess supply. Accordingly, we are carefully monitoring our capital budget and may implement further drilling rig reductions as required, sell assets to provide additional liquidity, or seek alternative financing arrangements.

The following table presents our liquidity and financial position as of March 31, 2013 and April 25, 2013:

(in thousands)	March 31, 2013		April 25, 2013
Cash (1) (2)	$	76,130	$	121,558
Drawings under the EXCO Resources Credit Agreement	494,234		494,234
2018 Notes (3)	750,000		750,000
Total debt (4)	1,244,234		1,244,234
Net debt	$	1,168,104	$	1,122,676
Borrowing base	$	900,000	$	900,000
Unused borrowing base (5)	$	398,259	$	398,259
Unused borrowing base plus cash (1) (5)	$	474,389	$	519,817

(1) Includes restricted cash of $53.3 million at March 31, 2013 and $38.6 million at April 25, 2013.

(2) Excludes our proportionate share of cash related to the EXCO/HGI Partnership of $3.8 million at March 31, 2013 and $0.7 million at April 25, 2013.

(3) Excludes unamortized bond premium of $8.2 million at March 31, 2013 and $8.1 million at April 25, 2013.

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(4) Excludes our proportionate share of the debt related to the EXCO/HGI Partnership of $95.4 million as of March 31, 2013 and April 25, 2013.

(5) Net of $7.5 million in letters of credit as of March 31, 2013 and April 25, 2013.

Credit agreements and long-term debt

Our consolidated debt consists of the EXCO Resources Credit Agreement, the 2018 Notes and our 25.5% proportionate share of the EXCO/HGI Partnership Credit Agreement (see "Note 9. Long-term debt" in the Notes to our Condensed Consolidated Financial Statements for a further description of each agreement). While our proportionate share of the EXCO/HGI Partnership's debt is consolidated, we are not a guarantor of the debt. We utilize the equity method of accounting for our investment in TGGT and therefore do not consolidate TGGT's debt. We are not a guarantor to any of TGGT's debt.

As of April 25, 2013, consolidated debt was $1.3 billion consisting of $494.2 million under the EXCO Resources Credit Agreement, $750.0 million under the 2018 Notes and $95.4 million representing our proportionate share of the EXCO/HGI Partnership Credit Agreement.

As of March 31, 2013, EXCO and the EXCO/HGI Partnership were in compliance with each of the covenants contained in the respective debt agreements, which are presented on the following table. Management believes the following table contains pertinent information related to our liquidity and compliance with the covenants within each agreement. However, the information is not complete and is qualified in its entirety by the terms of the EXCO Resources Credit Agreement and the EXCO/HGI Partnership Credit Agreement.

	As of March 31, 2013
(dollars in millions)	Borrowing base		Outstanding		Covenant type (2)	Required ratio (3)	Actual ratio
EXCO Resources:
EXCO Resources Credit Agreement (1)	$	900.0	$	494.2	Current ratio	> 1.0	3.9
					Leverage ratio	< 4.5	2.7
EXCO/HGI Partnership:
EXCO/HGI Partnership Credit Agreement (4)	$	470.0	$	374.0	Current ratio	> 1.0	3.4
					Leverage ratio	< 4.5	3.9

(1) Interest rates range from LIBOR plus 175-275 bps or ABR plus 75-175 bps depending on borrowing base usage. The EXCO Resources Credit Agreement matures in April 2016.

(2) As defined in the debt agreements.

(3) Maximum leverage permitted, or minimum coverage required per the debt agreement.

(4) Interest rates range from LIBOR plus 175-275 bps or ABR plus 75-175 bps depending on borrowing base usage. The EXCO/HGI Partnership Credit Agreement matures in February 2018.

The 2018 Notes mature in September 2018 and have a fixed interest rate of 7.5%. The indenture governing the 2018 Notes contains incurrence covenants which restrict our ability to incur additional indebtedness or pledge assets.

There are certain risks arising from the depressed natural gas prices that could impact our ability to meet debt covenants in future periods. In particular, our ratio of consolidated funded indebtedness to consolidated EBITDAX, as defined in the EXCO Resources Credit Agreement, is computed using a trailing 12-month computation of EBITDAX and only includes operations from non-guarantor subsidiaries and unconsolidated joint ventures to the extent that cash is distributed to entities under the EXCO Resources Credit Agreement. As a result, our ability to maintain compliance with this covenant is negatively impacted when oil and/or natural gas prices and production decline over an extended period of time. In addition, the formation of the EXCO/HGI Partnership resulted in a reduction to our outstanding debt and a reduction of our borrowing base under the EXCO Resources Credit Agreement from $1.3 billion to $900.0 million. Our future results of operations, cash flows from operations and proved reserves in future periods will be reduced by the 74.5% economic interest in the EXCO/HGI Partnership acquired by HGI in the first quarter of 2013 .

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Capital Expenditures

Our 2013 capital budget is $273.0 million, of which $220.0 million is allocated to development and completion activities. Our capital budget excludes any capital expenditures of the EXCO/HGI Partnership as these are expected to be funded through the partnership's internally generated cash flow and its credit agreement.

Our 2013 capital program is focused primarily on development of our Haynesville shale assets in North Louisiana with a three rig program and further appraisal of our Marcellus shale assets in Northeast Pennsylvania with a one rig program. In the Haynesville shale, we are targeting our core development area in DeSoto Parish, Louisiana. We plan to spend a total of $173.0 million targeting the Haynesville and Bossier shales, of which the majority will be spent for drilling and completion costs, including completion of wells that were in inventory at year-end 2012. Our drilling in this area will primarily be development on 80-acre spacing utilizing multi-well pads. During 2013, we plan to spend $56.0 million on our Marcellus shale program, which will be allocated to the completion of wells in inventory and drilling of five appraisal wells in Northeast Pennsylvania. Corporate expenditures are estimated to be $39.0 million, including $24.0 million of capitalized interest and $15.0 million of capitalized salaries.

The capital budget for the EXCO/HGI Partnership for 2013 is approximately $40.0 million, which is primarily focused on its Permian Basin assets in West Texas and its assets in North Louisiana. The program targets high probability of success projects that provide acceptable rates of return in the current commodity price environment. The EXCO/HGI Partnership plans to run one operated rig in the Permian Basin area targeting the Canyon Sand formation. The EXCO/HGI Partnership's capital program also includes recompletion projects in North Louisiana targeting the Hosston formation.

TGGT's capital budget for 2013 is approximately $40.0 million, which is primarily associated with field infrastructure pipelines to support projected drilling activity in North Louisiana and legacy East Texas areas.

The following table presents capital expenditures for the three months ended March 31, 2013 and our expected capital expenditures for the remainder of 2013.

	Three Months Ended March 31,		April - December Forecast		Full Year Forecast
(in thousands)	2013		2013		2013
Capital expenditures:
Development capital	$	58,715	$	161,285	$	220,000
Gas gathering and water pipelines	—		—		—
Lease acquisitions and seismic	—		14,000		14,000
Corporate and other	9,634		29,366		39,000
Total	$	68,349	$	204,651	$	273,000

Historical sources and uses of funds

Our primary sources of cash for the three months ended March 31, 2013 were cash flows from operations, proceeds from the contribution of assets to the EXCO/HGI Partnership, and other asset divestitures. In response to depressed natural gas prices, we have reduced our drilling programs and implemented company-wide cost reduction efforts. We were able to reduce our borrowings under the EXCO Resources Credit Agreement by $613.3 million during the three months ended March 31, 2013.

Net increases (decreases) in cash are summarized as follows:

	Three Months Ended March 31,
(in thousands)	2013			2012
Net cash provided by operating activities	$	43,214		$	145,123
Net cash provided by (used in) investing activities	525,260			(167,888		)
Net cash provided by (used in) financing activities	(587,472		)	21,339
Net decrease in cash	$	(18,998	)	$	(1,426	)

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Operating activities

The primary factors impacting our cash flows from operations generally include: (i) levels of production from our oil and natural gas properties, (ii) prices we receive from sales of oil, natural gas and natural gas liquids production, including settlement proceeds or payments related to our oil and natural gas derivatives, (iii) operating costs of our oil and natural gas properties, (iv) costs of our general and administrative activities and (v) interest expense. Our cash flows from operating activities have historically been impacted by fluctuations in oil and natural gas prices and our production volumes. The continued depressed natural gas price environment has had a significant negative impact on our cash flows from operating activities. In addition, the formation of the EXCO/HGI Partnership resulted in a reduction of 74.5% of our interest in certain conventional non-shale assets, which has reduced our cash flows from operating activities in the current period and will reduce cash flows from operating activities in future periods.

Net cash provided by operating activities for the three months ended March 31, 2013 was $43.2 million compared to $145.1 million for the three months ended March 31, 2012. The decrease is primarily attributable to unfavorable working capital conversions and lower settlement proceeds on our derivatives. Settlements on derivative contracts decreased by $33.4 million for the three months ended March 31, 2013 compared to the same period in prior year. The decrease in cash flows as a result of lower production from our interest in the properties contributed to the EXCO/HGI Partnership was offset by higher realized prices for the three months ended March 31, 2013 compared to the same period in prior year.

Investing activities

Our investing activities consist primarily of drilling and development expenditures, acquisitions and divestitures. Our current focus is directed toward producing property acquisitions with undeveloped upside potential. These acquisitions are dependent on oil and natural gas prices, availability of producing properties and attractive acreage, acceptable rates of return and availability of borrowing capacity under our credit agreements or from other capital sources.

For the three months endedMarch 31, 2013, our cash flows provided by investing activities were $525.3 million, compared with $167.9 million of cash flows used in investing activities for the three months ended March 31, 2012. The increase in cash flows provided was primarily attributable to the $573.3 million in proceeds as a result of the contribution of properties to the EXCO/HGI Partnership, the divestiture of certain properties for $37.9 million, and lower capital expenditures due to our reduced drilling program. This was partially offset by our proportionate share of the EXCO/HGI Partnership's acquisition of the shallow Cotton Valley assets from an affiliate of BG Group.

Financing activities

For the three months ended March 31, 2013, our outstanding borrowings under the EXCO Resources Credit Agreement were reduced by $613.3 million primarily due to the proceeds received from the contribution of assets to the EXCO/HGI Partnership, cash flows from operations and other divestitures. In addition, cash payments for dividends on our common stock totaled $10.7 million during the quarter. This was partially offset by the additional borrowings of the EXCO/HGI Partnership to fund the acquisition of shallow Cotton Valley assets from an affiliate of BG Group.

Derivative financial instruments

Our production is generally sold at prevailing market prices. However, we periodically enter into oil and natural gas derivative contracts for a portion of our production when market conditions are deemed favorable and oil and natural gas prices exceed our minimum internal price targets. Our objective in entering into oil and natural gas derivative contracts is to mitigate the impact of price fluctuations and achieve a more predictable cash flow associated with our operations. These transactions limit our exposure to declines in prices, but also limit the benefits we would realize if oil and natural gas prices increase.                     

Our derivative financial instruments are comprised of oil and natural gas swap and call option contracts. We do not designate these instruments as hedging instruments for financial accounting purposes and, accordingly, we recognize the change in the respective instruments' fair value currently in earnings, as a gain or loss on oil and natural gas derivatives. As of March 31, 2013, we had derivative financial instruments in place for the volumes and prices shown below:

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(in thousands, except prices)	NYMEX gas volume - Mmbtu	Weighted average contract price per Mmbtu		NYMEX oil volume - Bbls	Weighted average contract price per Bbl
Swaps:
Q2 2013	21,915	$	4.13	35	$	94.05
Q3 2013	22,460	4.13		35	94.05
Q4 2013	22,460	4.13		35	94.05
2014	56,648	4.25		93	91.87
2015	28,288	4.31		—	—
Calls:
Q2 2013	5,005	$	4.29	—	$	—
Q3 2013	5,060	4.29		—	—
Q4 2013	5,060	4.29		—	—
2014	20,075	4.29		365	100.00
2015	20,075	4.29		365	100.00

We proportionately consolidate the derivative financial instruments entered into by the EXCO/HGI Partnership. However, the EXCO/HGI Partnership is considered to be an unrestricted subsidiary and we are not liable in the event of default on their derivative contracts. As of March 31, 2013, our proportionate share of the EXCO/HGI Partnership's natural gas derivative swap contracts included approximately 19,000 Mmbtus per day at an average price of $3.72 during 2013, and 10,000 Mmbtus per day at an average price of $4.14 during 2014. Our proportionate share of the EXCO/HGI Partnership's oil derivative swap contracts included approximately 383 Bbls per day at an average price of $94.05 during 2013, and 255 Bbls per day at an average price of $91.87 during 2014. The EXCO/HGI Partnership had derivative financial instruments that covered approximately 54.4% of production volumes during the period from its inception until March 31, 2013.

See further details on our derivative financial instruments in "Note 7. Derivative financial instruments" and "Note 8. Fair value measurements" in the Notes to our Condensed Consolidated Financial Statements.

Off-balance sheet arrangements

As of March 31, 2013, we had no arrangements or any guarantees of off-balance sheet debt to third parties.

Contractual obligations and commercial commitments

There have been no material changes outside the ordinary course of business to our contractual obligations and commercial commitments since December 31, 2012.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Some of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices, and interest rates charged on borrowings. The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonably possible losses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitive instruments were entered into for hedging and investment purposes, not for trading purposes.

Commodity price risk

Our objective in entering into derivative financial instruments is to manage our exposure to commodity price fluctuations, protect our returns on investments, and achieve a more predictable cash flow in connection with our financing activities and borrowings related to these activities. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if oil and natural gas prices increase. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expense due to changes in the fair value of our derivative financial instrument contracts. Cash charges or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration.

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Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices for natural gas. Pricing for oil and natural gas production is volatile.

Our use of derivative financial instruments could have the effect of reducing our revenues and the value of our

securities. For the three months ended March 31, 2013, a $1.00 increase in the average commodity price per Mcfe would have resulted in an increase in cash settlement payments (or a decrease in settlements received) of approximately $18.5 million. The ultimate settlement amount of our outstanding derivative financial instrument contracts is dependent on future commodity prices. We may incur significant unrealized losses in the future from our use of derivative financial instruments to the extent market prices increase and our derivatives contracts remain in place.

Interest rate risk

Our exposure to interest rate changes is related primarily to borrowings under the EXCO Resources Credit Agreement and the EXCO/HGI Partnership Credit Agreement. The interest rate per annum on the 2018 Notes is fixed at 7.5%. Interest is payable on borrowings under the EXCO Resources Credit Agreement and EXCO/HGI Partnership Credit Agreement based on a floating rate as more fully described in “Note 9. Long-term debt” in the Notes to our Condensed Consolidated Financial Statements. At March 31, 2013, we had approximately $494.2 million in outstanding borrowings under the EXCO Resources Credit Agreement and approximately $95.4 million for our proportionate share of outstanding borrowings under the EXCO/HGI Partnership Credit Agreement. A 1% change in interest rates (100 bps) based on the variable borrowings as of March 31, 2013 would result in an increase or decrease in our interest expense of $5.9 million per year. The interest we pay on these borrowings is set periodically based upon market rates.

Item 4. Controls and Procedures

Disclosure controls and procedures. Pursuant to Rule 13a-15(b) under the Exchange Act, EXCO’s management has evaluated, under the supervision and with the participation of our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act), as of the end of the period covered by this report. This evaluation included consideration of various processes and procedures to ensure that information that is required to be disclosed by EXCO in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to EXCO’s management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Based upon this evaluation, our principal executive officer and principal financial officer concluded that, as of March 31, 2013, our disclosure controls and procedures were effective.

Changes in internal control over financial reporting. There were no changes in EXCO's internal control over financial reporting that occurred during the quarter ended March 31, 2013 that have materially affected, or are reasonably likely to materially affect, EXCO's internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

In the ordinary course of business, we are periodically a party to various litigation matters. We do not believe that any resulting liability from existing legal proceedings, individually or in the aggregate, will have a material adverse effect on our results of operations or financial condition.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer repurchases of ordinary shares

The following table details our repurchase of common shares for the three months ended March 31, 2013:

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Period	Total Number of Shares Purchased (1)	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (1)
January 1, 2013 - January 31, 2013	—	$	—	—	$ 192.5 million
February 1, 2013 - February 28, 2013	—	—		—	192.5 million
March 1, 2013 - March 31, 2013	—	—		—	192.5 million
Total	—	$	—	—

(1) On July 19, 2010, we announced a $200.0 million share repurchase program.

Item 6. Exhibits

See “Index to Exhibits” for a description of our exhibits.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

			EXCO RESOURCES, INC.
			(Registrant)
Date:	May 1, 2013	By:	/s/ Douglas H. Miller
			Douglas H. Miller
			Chairman and Chief Executive Officer
		By:	/s/ Mark F. Mulhern
			Mark F. Mulhern
			Executive Vice President and Chief Financial Officer

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INDEX TO EXHIBITS

Exhibit

Number Description of Exhibits________________________________________________________________________________________

 2.1 Unit Purchase and Contribution Agreement, dated November 5, 2012, by and among EXCO Resources, Inc., EXCO Operating Company, LP, EXCO/HGI JV Assets, LLC and HGI Energy Holdings, LLC, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated November 5, 2012 and filed on November 9, 2012 and incorporated by reference herein.

2.2 First Amendment to Unit Purchase and Contribution Agreement and Closing Agreement, dated as of February 14, 2013, by and among EXCO Resources, Inc., EXCO Operating Company, LP, EXCO/HGI JV Assets, LLC and HGI Energy Holdings, LLC, filed herewith.

3.1 Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO's Current Report on Form 8-K (File No. 001-32743), dated February 8, 2006 and filed on February 14, 2006 and incorporated by reference herein.

3.2 Articles of Amendment to the Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO's Current Report on Form 8-K (File No. 001-32743), dated August 30, 2007 and filed on September 5, 2007 and incorporated by reference herein.

3.3 Second Amended and Restated Bylaws of EXCO Resources, Inc., filed as an Exhibit to EXCO's Current Report on Form 8-K, dated March 4, 2009 and filed on March 6, 2009 and incorporated by reference herein.

3.4 Statement of Designation of Series A-l 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO's Current Report on Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

3.5 Statement of Designation of Series A-2 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO's Current Report on Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

3.6 Statement of Designation of Series B 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO's Current Report on Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

3.7 Statement of Designation of Series C 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO's Current Report on Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

3.8 Statement of Designation of Series A-l Hybrid Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO's Current Report on Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

3.9 Statement of Designation of Series A-2 Hybrid Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO's Current Report on Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

 3.10 Statement of Designation of Series A Junior Participating Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO's Current Report on Form 8-K, dated January 12, 2011 and filed on January 13, 2011 and incorporated by reference herein.

 4.1 Indenture, dated September 15, 2010, by and between EXCO Resources, Inc. and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated September 10, 2010 and filed on September 15, 2010 and incorporated by reference herein.

 4.2 First Supplemental Indenture, dated September 15, 2010, by and among EXCO Resources, Inc., certain of its subsidiaries and Wilmington Trust Company, as trustee, including the form of 7.500% Senior Notes due 2018,

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filed as an Exhibit to EXCO's Current Report on Form 8-K, dated September 10, 2010 and filed on September 15, 2010 and incorporated by reference herein.

4.3 Second Supplemental Indenture, dated as of February 12, 2013, by and among EXCO Resources, Inc., EXCO/HGI JV Assets, LLC, EXCO Holding MLP, Inc. and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated February 12, 2013 and filed on February 19, 2013 and incorporated by reference herein

4.4 Specimen Stock Certificate for EXCO's common stock, filed as an Exhibit to EXCO's Amendment No. 2 to the Form S-l (File No. 333-129935), filed on January 27, 2006 and incorporated by reference herein.

4.5 First Amended and Restated Registration Rights Agreement, by and among EXCO Holdings Inc. and the Initial Holders (as defined therein), effective January 5, 2006, filed as an Exhibit to EXCO's Amendment No. 1 to its Registration Statement on Form S-l (File No. 333-129935), filed on January 6, 2006 and incorporated by reference herein.

10.1 Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Current Report on Form 8-K (File No. 001-32743), dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*

10.2 Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Current Report on Form 8-K (File No. 001-32743), dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*

10.3 Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Current Report on Form 8-K (File No. 001-32743), dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*

10.4 Form of Restricted Stock Award Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated August 4, 2011 and filed on August 10, 2011 and incorporated by reference herein.*

10.5 Fourth Amended and Restated EXCO Resources, Inc. Severance Plan, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated March 16, 2011 and filed on March 22, 2011 and incorporated by reference herein.*

10.6 Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO's Current Report on Form 8-K (File No. 001-32743), dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*

10.7 Amendment Number One to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2009 filed February 24, 2010 and incorporated by reference herein.*

10.8 Letter Agreement, dated March 28, 2007, with OCM Principal Opportunities Fund IV, L.P. and OCM EXCO Holdings, LLC, filed as an Exhibit to EXCO's Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

10.9 Letter Agreement, dated March 28, 2007, with Ares Corporate Opportunities Fund, ACOF EXCO, L.P., ACOF EXCO 892 Investors, L.P., Ares Corporate Opportunities Fund II, L.P., Ares EXCO, L.P. and Ares EXCO 892 Investors, L.P, filed as an Exhibit to EXCO's Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

10.10 Amendment Number One to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an exhibit to EXCO's Current Report on Form 8-K, dated June 4, 2009 and filed on June 10, 2009 and incorporated by reference herein.*

10.11 Amendment Number Two to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, dated as of October 6, 2011, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated October 6, 2011 and filed on October 7, 2011 and incorporated by reference herein.*

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10.12 Joint Development Agreement, dated August 14, 2009, by and among BG US Production Company, LLC, EXCO Operating Company, LP and EXCO Production Company, LP, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated August 11, 2009 and filed on August 17, 2009 and incorporated by reference herein.

10.13 Amendment to Joint Development Agreement, dated February 1, 2011, by and among BG US Production Company, LLC and EXCO Operating Company, LP, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated by reference herein.

10.14 Amended and Restated Limited Liability Company Agreement of TGGT Holdings, LLC, dated August 14, 2009, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated August 11, 2009 and filed on August 17, 2009 and incorporated by reference herein.

10.15  First Amendment to Amended and Restated Limited Liability Company Agreement of TGGT Holdings, LLC, dated January 31, 2011, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated by reference herein.

10.16 Joint Development Agreement, dated as of June 1, 2010, by and among EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.17 Amendment to Joint Development Agreement, dated February 4, 2011, by and among EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated by reference herein.

10.18 Second Amended and Restated Limited Liability Company Agreement of EXCO Resources (PA), LLC, dated June 1, 2010, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.19 Second Amended and Restated Limited Liability Company Agreement of Appalachia Midstream, LLC, dated June 1, 2010, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and Appalachia Midstream, LLC, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.20 Letter Agreement, dated June 1, 2010 and effective as of May 9, 2010, by and between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.21 Guaranty, dated May 9, 2010, by BG Energy Holdings Limited in favor of EXCO Holding (PA), Inc., EXCO Production Company (PA), LLC and EXCO Production Company (WV), LLC, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.22 Performance Guaranty, dated May 9, 2010, by EXCO Resources, Inc. in favor of BG US Production Company, LLC, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.23 Guaranty, dated June 1, 2010, by BG North America, LLC in favor of (i) EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC and EXCO Resources (PA), LLC; and (ii) EXCO Resources (PA), LLC and EXCO Holding (PA), Inc, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.24 Guaranty, dated June 1, 2010, by EXCO Resources, Inc., in favor of: (i) BG Production Company (PA), LLC, BG Production Company (WV), LLC and EXCO Resources (PA), LLC; and (ii) EXCO Resources (PA), LLC and BG US Production Company, LLC, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

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10.25 Credit Agreement, dated as of April 30, 2010, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Book runner and Lead Arranger, Wells Fargo Securities, LLC, as Co-Lead Arranger, Bank of America, N.A. and BNP Paribas, as Co-Lead Arrangers and Co-Syndication Agents, Royal Bank of Canada, as Co-Lead Arranger and Co-Documentation Agent, Wells Fargo Bank, National Association, as Co-Documentation Agent, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated July 16, 2010 and filed on July 22, 2010 and incorporated by reference herein.

10.26 First Amendment to Credit Agreement, dated as of July 16, 2010, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Bank of America, N.A. and BNP Paribas, as Co-Lead Arrangers and Co-Syndication Agents, Royal Bank of Canada, as Co-Lead Arranger and Co-Documentation Agent, Wells Fargo Bank, National Association, as Co-Documentation Agent, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated July 16, 2010 and filed on July 22, 2010 and incorporated by reference herein.

10.27 Second Amendment to Credit Agreement, dated as of September 15, 2010, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Bank of America, N.A. and BNP Paribas, as Co-Lead Arrangers and Co-Syndication Agents, Royal Bank of Canada, as Co-Lead Arranger and Co-Documentation Agent, and Wells Fargo Bank, National Association, as Co-Documentation Agent, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated September 10, 2010 and filed on September 15, 2010 and incorporated by reference herein.

10.28 Third Amendment to Credit Agreement, dated as of April 1, 2011, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated April 1, 2011 and filed on April 4, 2011 and incorporated by reference herein.

10.29 Fourth Amendment to Credit Agreement, dated as of November 8, 2011, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated November 8, 2011 and filed on November 9, 2011 and incorporated by reference herein.

10.30 Fifth Amendment to Credit Agreement, dated as of November 8, 2011, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated November 8, 2011 and filed on November 9, 2011 and incorporated by reference herein.

10.31 Sixth Amendment to Credit Agreement, dated as of April 27, 2012, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2012, filed on May 2, 2012 and incorporated by reference herein.

10.32 Form of Director Indemnification Agreement, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated November 10, 2010 and filed on November 12, 2010 and incorporated by reference herein.

10.33 Credit Agreement, dated January 31, 2011, by and among TGGT Holdings, LLC, its subsidiaries, as borrowers (or guarantor as to one TGGT subsidiary), JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities Inc., as sole bookrunner and co-lead arranger, BNP Paribas, Citibank, N.A., The Royal Bank of Scotland PLC and Wells Fargo Securities, LLC, as co-lead arrangers, and the lenders named therein, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated by reference herein.

10.34 First Amendment to Credit Agreement, dated January 25, 2012, by and among TGGT Holdings, LLC, TGG Pipeline, Ltd. And Talco Midstream Assets, Ltd., as Borrowers, TGGT GP Holdings, LLC and certain subsidiaries of Borrowers, as Guarantors, JPMorgan Chase Bank, N.A., as Administrative Agent, J.P. Morgan Securities LLC, as Sole Bookrunner and Co-Lead Arranger, Wells Fargo Securities, LLC, Bank of America, N.A., BMO Harris Financing, Inc., Royal Bank of Canada, Morgan Stanley Senior Funding, Inc., UBS Loan Finance LLC and The Royal Bank of Scotland plc, as Co-Lead Arrangers, and the lenders party thereto, filed as an Exhibit to EXCO's

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Current Report on Form 8-K, dated January 25, 2012 and filed on January 31, 2012 and incorporated by reference herein.

10.35 EXCO Resources, Inc. Retention Bonus Plan, dated August 4, 2011, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated August 4, 2011 and filed on August 10, 2011 and incorporated by reference herein.*

10.36 Amended and Restated Agreement of Limited Partnership of EXCO/HGI Production Partners, LP, filed herewith.

10.37 Form of Amended and Restated Limited Liability Company Agreement of EXCO/HGI GP, LLC, filed herewith.

10.38 Letter Agreement, dated November 5, 2012, by and among EXCO Resources, Inc., EXCO Operating Company, LP, Harbinger Group Inc. and HGI Energy Holdings, LLC, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated November 5, 2012 and filed on November 9, 2012 and incorporated by reference herein.

10.39 Seventh Amendment to Credit Agreement, dated as of October 30, 2012, by and among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated October 30, 2012 and filed on November 5, 2012 and incorporated by reference herein.

10.40 Transition Consulting Agreement, dated February 28, 2013, by and between EXCO Resources, Inc. and Stephen F. Smith, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated February 28, 2013 and filed on March 6, 2013 and incorporated by reference herein.*

10.41 Letter Agreement, dated March 1, 2013, by and between EXCO Resources, Inc. and Mark Mulhern, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated February 28, 2013 and filed on March 6, 2013 and incorporated by reference herein.*

10.42 EXCO Resources, Inc. 2013 Management Incentive Plan, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated February 28, 2013 and filed on March 6, 2013 and incorporated by reference herein.*

10.43 Credit Agreement, dated as of February 14, 2013, among EXCO/HGI JV Assets, LLC, as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities LLC, as Sole Book runner and Lead Arranger, Bank of America, N.A. and Deutsche Bank Trust Company Americas, as Co-Syndication Agents, and UBS Securities LLC and BMO Harris Financing, Inc., as Co-Documentation Agents, filed herewith.

10.44 First Amendment to Credit Agreement, dated as of March 5, 2013, by and among EXCO/HGI JV Assets, LLC, as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, filed herewith.

31.1 Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer of EXCO Resources, Inc., filed herewith.

31.2 Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer of EXCO Resources, Inc., filed herewith.

32.1 Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer and Chief Financial Officer of EXCO Resources, Inc., filed herewith.

101.INS**  XBRL Instance Document.

101.SCH**  XBRL Taxonomy Extension Schema Document.

101.CAL**  XBRL Taxonomy Calculation Linkbase Document.

101.DEF**  XBRL Taxonomy Definition Linkbase Document.

101.LAB**  XBRL Taxonomy Label Linkbase Document.

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101.PRE** XBRL Taxonomy Presentation Linkbase Document.

* These exhibits are management contracts.

** Furnished with this report. In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.

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